Systems and methods of semi-centralized power storage and power production for multi-directional smart grid and other applications

ABSTRACT

Systems and methods of semi-centralized power storage and distributed power generation comprise at least one power storage facility at a first location, at least one distributed power generation facility at a second location different than the first location, and at least one mobile stored power transportation unit. The power storage facility includes a power storage medium comprising liquid air, nitrogen, oxygen, or a combination thereof. The mobile stored power transportation unit is configured to carry at least a portion of the power storage medium to the distributed power generation facility. In exemplary embodiments, the power storage facility is an air separation plant. The power storage facility may also function as an energy service company.

FIELD

The present disclosure relates to systems and methods ofsemi-centralized power storage and distributed power generation, as wellas methods of enhancing the integration of the electric grid and gaspipeline systems.

BACKGROUND

Storage of electric power allows low-value power produced “off-peak”(e.g., overnight) to be released during “peak” power demand periods(e.g., daytime) when the value of power is substantially higher and whenpower shortages are most likely to occur. This is true regardless of thesource (e.g., coal-fired power, nuclear power, wind power, etc.) of the“original” power to be stored. Numerous important benefits result frommulti-megawatt (“bulk”) power storage methods, including using off-peakenergy to provide more peak power, expanding the amount of higher-valuepeak power that can be delivered through existing transmission anddistribution infrastructure, and transforming intermittent (unreliable)power sources such as wind and solar into “firm,” “dispatchable”(reliable) sources.

Generally, electrical grids can only tolerate +/−10% intermittentrenewable power as a percentage of the total power supply on the grid,because allowing significantly more intermittent power would cause thegrid to become unstable/unreliable and may “crowd-out” the more reliable(and thus more valuable) power from baseload plants. This represents a“ceiling” for the market penetration of intermittent renewable powersources in the absence of a cost-effective, broadly deployable bulkpower storage solutions such as the disclosed embodiments. In addition,smaller multi-megawatt energy storage systems (e.g., 1 MW to 50 MW)provide a means to add peak power capacity to constrained load pocketsat high net efficiency while helping to upgrade (and, in effect, expand)power distribution systems, especially in areas where few other optionsexist and/or where upgrades are costly.

There are many benefits of bulk power storage to the electrical grid,including but not limited to the ability to buy electric energy low(off-peak) and sell high (peak), greater electric supply capacity,elimination of the need for “peaker” power plants, reduction oftransmission capacity requirements and congestion, better electricservice reliability and power quality, reduction in electric bills, andfirming of renewables capacity. Not all of the above power storagevalues apply for each deployment of a storage asset, because theindividual values that can be garnered are case-specific. However, as ageneral rule, the closer the power “release” of a power storage systemis to the load, the more benefit it will bring to the overall electricalgrid, including but not limited to, utilities, ISOs and rate-payers.Thus, systems such as the disclosed embodiments whose power release canoccur close to the power load are more valuable than those that can onlybe deployed far “upstream” on the grid.

Despite the many advantages of bulk power storage identified above,there are very few market-ready power storage options in the lowercommercial scale range, e.g., 1 MW to 50 MW. Battery technologies aregenerally limited to a few MW/MWH of capacity (under 5 MW/10 MWH perday) and have other drawbacks including disposal issues at the end ofthe life of the batteries and limited discharge durations (generallyless than 2 hours per day). There are several available methods forlarge, utility-scale (greater than 100 MW) power storage, includingCompressed Air Energy Storage (CAES), pumped hydro, and liquid airenergy storage (LAES) such as Vandor's Power Storage (VP S) Cycle. CAESis severely limited by the need for caverns and/or other undergroundgeological formations that are required to contain the compressed air.Also, CAES does not deliver a consistent amount of power output; rather,the amount of power generated declines with each hour of power release,as the pressure of the compressed air in the cavern decreases throughoutthe daily cycle. Pumped hydro is also limited by geography and geology,requiring two large “lakes” to be separated by a significant heightdifferential between the two reservoirs, with a dam and water-turbinesbetween them.

VPS is much more flexible because it is not constrained bygeography/geology and can be placed near the end user of the power,i.e., at the load, thus enhancing the deployment's value. However, inorder to increase the total number of possible deployment sites, thebasic principles of VPS, and the methods and systems embodied in theprevious patents, need to be enhanced to allow for the technology to bedeployable not only at utility scales, (which can be characterized asapproximately 50 MW/400 MWH and larger), but also at smaller,“commercial scales,” which will typically be as small as about 1 MW, butcould be even smaller, i.e., in the kW scale. A network of widelydeployed, smaller-than utility-scale, power storage facilities willconstitute a “distributed power storage” system. Such a system offersmany benefits, including flexibility as to how the inflow to storageoccurs on the grid and as to how the outflow from storage is sent out topower users.

The various pumped hydro, and the two CAES deployments now operatingworldwide, are the largest-scale examples of power storage, where eachdeployment can send out hundreds of megawatts of power. At the other endof the scale, proposals have been put forth for using the power storagecapacity of the batteries in all-electric cars as a “crowd source”distributed power network where each car provides only a few kW of poweroutput (when it is plugged in to a two-way connection to the grid), butwhere the cumulative effect of many such plugged in cars may besignificant. Thus, there is a need for an energy storage system thatfits within the gap that exists between those two extremes, and whichgap is not now served by commercially viable technologies.

In addition to the power storage issues outlined briefly above, thepower distribution network faces another set of related challenges thatare best solved by “distributed power generation” systems and methods.For example, if the power distribution network is to be more reliable,it needs to be restructured. In particular, there is a need for anenergy production and distribution system that relies less onlarge-scale, centralized power plants located far from their customers,where an increasingly congested and vulnerable (to natural and man-madeevents) grid connects large generating facilities with a customer base.Instead, there is a need for power generation that can be employed atlower capital cost and more locally, near customers, providing forredundancy, shorter travel times/distances on the grid (reducing linelosses and congestion), and allowing for more competition in the marketand at a pricing structure that reflects the multiple options forlocalized (distributed) power production. The smaller the economic andtechnical “threshold” for distributed power production systems the morewidely they can be deployed, the more “distributed” the deployments, themore such a network can avoid grid congestion, and the less vulnerablethe grid becomes to unplanned natural and man-made outages i.e., byrelying on numerous widespread generation sources instead of just one(or several) large, centralized power plants).

Accordingly, there is a need for power storage systems and methods,which can transform low-value, off-peak power into high-value peak powerand which can make intermittent power sources “firm.” There is a furtherneed for power storage and distributed generation systems and methodsthat can be widely deployed at smaller commercial scales. Finally, Thereis also a need for power storage and distributed generation systems andmethods, which can be located close to power consumers (i.e., loadcenters).

SUMMARY

The embodiments of the present disclosure alleviate to a great extentthe disadvantages of known utility-scale power storage systems and powerproduction systems by using Liquid Air (L-Air), liquid oxygen and/orliquid nitrogen and/or some combination thereof (O₂/N₂ from this pointforward) as working fluids that can be produced during off-peak periods,transported in trailers and rail cars, and stored in above-ground,low-to moderate-pressure, cryogenic storage tanks, for release duringpeak power demand periods, but at scales and in configurations thatallow for commercial-scale storage and power generation (i.e., release)deployments, and allow the storage components to be locatedindependently of the power generation (release) components. Disclosedembodiments can provide distributed power storage from as low as kWscale or approximately 1 MW (referred to herein as “commercial-scale” or“Commercial-Scale” VPS) to utility-scales, which can be defined, asabove, as 50 MW or larger.

Fundamentally, embodiments of the present disclosure convertinflow-to-storage electric power into liquid air (L-Air) or into liquidoxygen or liquid nitrogen, which are components of air. Air is abundant,free, and non-toxic, so any “leaks” will not harm the environment. Theother components of air, such as carbon dioxide, argon, neon, helium,krypton and xenon have value and are recoverable during the O₂/N₂production process. As such, the air that is processed for embodimentsof the present disclosure will yield valuable byproducts.

Disclosed embodiments allow for the widespread integration of theelectric grid with other fuel sources such as the natural gas pipelinenetwork, making every site that has access to both distribution systemsa potential power storage facility, a potential distributed powergenerating facility, or both a power storage and a power generatingfacility. That integration of those two widely deployed networks—theelectric grid and the gas pipeline system—has, to date, only beenpossible at selected sites where large-scale gas-fired power plants orsimple-cycle gas turbines (“peak shaving” or “peaker” plants) aredeployed. Without embodiments of the present disclosure, the vastmajority of customers for electric power and natural gas cannotoptimally “connect” the two “delivery systems” they have access to, anddo not have options for localized power storage or for cost-effectivedistributed power production, and certainly have no options forachieving both.

In addition to “stand-alone” commercial-scale VPS plants, embodiments ofthe disclosure allow for the integration of VPS technology with existingsimple-cycle gas-fired power plants (e.g., “peakers”). In other words,existing simple-cycle power plants can be retrofitted with VPStechnology to convert them into “daily duty” baseload power storage anddispensing assets—making them far more valuable assets than theoccasionally-used peakers that they are today. Hundreds of such peakersexist around the world, representing a large market opportunity for thedeployment of disclosed systems, advancing the goals of distributedpower storage and distributed power generation. Disclosed embodimentscould eliminate the need for simple-cycle peaker plants entirely,including by retrofitting existing peakers.

Embodiments of the present disclosure are generally smaller, simpler andlower-cost than the previously patented versions of VPS, and address aneven broader and larger market opportunity/need. Disclosed embodimentscan be modular, standardized, factory-built “appliances” at scales of 1MW to 20 MW (or more)—scales where today there is virtually nocost-effective technological solution, as such scales are generally toosmall for CAES and pumped hydro and too large for battery storage.

Embodiments of the present disclosure represent a potential “paradigmshift” in how energy is produced, delivered, stored and used, and assuch is a (beneficially) “disruptive” technology. Worldwide, virtuallyevery facility that uses about 1 MW or more of power from the electricgrid and is served by a natural gas grid connection (or other source ofnatural gas) is a candidate site for the disclosed embodiments. Eachsuch deployment could eventually become part of a widespread network ofcost-effective, low-emissions semi-centralized storage and distributedgeneration assets, combining the well-recognized economic andoperational benefits of power storage and distributed generation—two ofthe most important trends in the power industry today.

An additional element of the potential paradigm shift that the disclosedembodiments provide is the opportunity for whole new business models,including but not limited to “merchant” power-storage/power-deliverybusinesses, operating similar to energy services companies (ESCOs). Suchmerchants could produce the stored power at their own (or others')cryogenic plants, and sell/transport that stored power to distributedpower generators and/or power consumers, as described in other sectionsherein. Thus, perhaps for the first time, through the disclosedembodiments, “merchants” in the power industry could not only supplypower generation (and occasionally power storage) as they do today, butthey could also provide power distribution (similar to the function ofutilities).

A further potential new system, method and business model would be a“de-linked” (both physically and economically) power storage anddelivery system, whereby power is stored in one location (usually on theelectrical grid) and sold/transported to one or more other locationswithout using/requiring an electrical grid (or even an electricaldistribution line) to reach the power to that destination point. Assuch, disclosed embodiments would also allow a whole newsaleable/tradable commodity (stored power) to emerge in the energyindustry. Such stored energy would not be limited to just one or a fewsuppliers or customers (as electricity generally is today) because thedisclosed embodiments do not rely on the “fixed” electrical grid toreach its point of use. Further, the disclosed embodiments would yield asubstantially more nimble and flexible electrical system.

Power storage assets have historically relied on a single connection toa source of electricity to function. That presents challenges in termsof reliability of power supply (reliance on a single source) and interms of pricing (little or no competition of supply due to the need toreceive power from a single grid connection). Disclosed embodiments“break that mold” by allowing stored power to be delivered (in the formof a mobile (e.g., truckable) cryogenic fluid) from many sources ofsupply (e.g., multiple suppliers of L-Air, O₂ or N₂), bringing the powerstorage and power generation market substantially closer to whateconomists call a “perfect market” (i.e., many suppliers and manycustomers, each having choice), benefiting the whole electrical systemand the rate-payers. This reduces the need for the “natural monopolies”(i.e., regulated utilities) that have controlled the grid's power supplyand distribution for many decades, allowing for a more de-regulated,“market-based” power industry. Similarly, disclosed embodiments willreduce the need for large, centralized (often distantly located) powerplants, which are very expensive to construct, and often requirehigh-capacity/high-voltage interstate/intrastate transmission lines,which are difficult to permit and construct. Thus, through disclosedembodiments, power markets can be reliably “localized,” yieldingnumerous significant benefits.

Because of the disclosed embodiments' wide range of scales and theirinherent flexibility as described herein (e.g., the mobility of thepower storage units), disclosed embodiments are suitable for a widevariety of potential deployment sites/end-users, including but notlimited to, the following:

Industrial facilities/factories/refineries

Microgrids

Utility—T&D “tight spots”/capacity upgrades

Military bases

Hospitals

Office parks/corporate campuses

Shopping centers

Airports & shipping ports

Wind farms & solar farms

University campuses

Data centers/server farms

Food processing/refrigerated warehouses

Mines & quarries

Other critical buildings/infrastructure

Because embodiments of the present disclosure allow surplus powergenerated at the distributed power production site (above the amount ofpower needed by the host site) to be sold to the grid (either by thehost/asset owner or by a third-party ESCO or power broker/trader),disclosed embodiments include a significant enabling technology toadvance the development/utilization of a multi-directional “smart grid,”which power utilities and power systems manufacturers have promoted inrecent years. An optimal smart grid needs power sourced from manylocations, and flowing in multiple directions, which can change quicklybased on supply and demand conditions. Owners/users of disclosedembodiments would be not only power consumers, but also power providers.

This allows many more power suppliers to enter the market forelectricity supply, “democratizing” the market by reducing/eliminatingthe historical reliance on a single (or a few) large powergenerators/utilities. This is particularly true because disclosedembodiments are deployable at relatively small scales (e.g., as low askW scale and approximately 1 MW), reducing “barriers-to-entry” by makingit easier and less expensive for many parties to purchase/own/leasepower storage and generation assets. Thus, competition in the powersupply market would be increased (a major goal of utility regulators andpolicy makers in recent decades) through the widespread deployment ofdisclosed embodiments, thereby benefiting power consumers/rate-payers,including by keeping power prices low. Additionally, independent systemoperators (ISOs) who manage the grid would benefit from havingadditional, more distributed sources of power supply to rely upon inorder to “balance” the market and ensure that power is available whenand where needed. It should be noted that each distributed powerproduction site envisioned by the present disclosure may also receive“power” from more than one supplier, further providing “certainty” andcompetition.

Exemplary systems of semi-centralized power storage and distributedpower generation comprise at least one power storage facility at a firstlocation, at least one distributed power generation facility at a secondlocation different than the first location, and at least one mobilestored power transportation unit. The power storage facility includes apower storage medium comprising liquid air, nitrogen, oxygen, or acombination thereof. The mobile stored power transportation unit isconfigured to carry at least a portion of the power storage medium tothe distributed power generation facility. In exemplary embodiments, thepower storage facility is an air separation plant. In exemplaryembodiments, the power storage facility functions as an energy servicecompany, also known as an ESCO. Exemplary embodiments may furthercomprise at least one power storage facility at a third location,wherein at least one mobile stored power transportation unit transportspower storage medium from the third location to the distributed powergeneration facility

In exemplary embodiments, the distributed power generation facility iselectrically connected to an electric grid and provides power to thegrid, which could be surplus power (beyond the needs of the adjacentpower consumer(s)) to the grid. Exemplary systems may further compriseat least one power producer providing power to the power storagefacility. The power storage facility may be configured to use a portionof the stored power in a distributed power generation mode. A naturalgas pipeline and a prime mover, such as a turbine or an engine, may beprovided with the power storage facility to enable it to use the power.Exemplary embodiments include a natural gas pipeline fluidly connectedto the distributed power generation facility.

In exemplary embodiments, the power storage facility comprises aplurality of compressors, at least one heat exchanger fluidly connectedto at least one of the compressors, at least one expander fluidlyconnected to at least one of the compressors, a mechanical chillerfluidly connected to the expander, and a storage vessel fluidlyconnected to the expander. An exemplary distributed power generationfacility may comprise a plurality of heat exchangers, at least oneexpander fluidly connected to at least one of the heat exchangers, and aprime mover assembly including a prime mover. The prime mover assemblymay be fluidly connected to at least one of the heat exchangers.

Exemplary embodiments may further comprise a prime mover fluidlyconnected to the distributed power generation facility, wherein theprime mover functions as a back-up generator. In exemplary embodiments,semi-centralized power storage and distributed power generation systemsfurther comprise a mobile vehicle including a prime mover, the primemover being fluidly connected to the distributed power generationfacility. The prime mover may be a fueled turbine that provides aportion of the power supplied by the distributed power generationfacility. The prime mover may be a fueled turbine, and the power storagemedium cools inlet air stream to the turbine. The system may be acommercial scale deployment. In exemplary embodiments, the systemcomprises at least one power storage facility at a third locationdifferent than the first location, wherein at least one mobile storedpower transportation unit transports power storage medium from the thirdlocation to the distributed power generation facility. The at least onemobile stored power transportation may carry at least a portion of thepower storage medium off-grid to the distributed power generationfacility

Exemplary embodiments include a method of semi-centrally storing energyand distributing power comprising storing power at a first location in apower storage medium, transporting at least a portion of the powerstorage medium to a second location different than the first location,and releasing power from the power storage medium to generate power atthe second location. The power storage medium comprises liquid air,nitrogen, oxygen, or a combination thereof. In exemplary embodiments,storing power comprises separating air into oxygen, nitrogen, or acombination thereof. The step of storing power may also compriseproviding a stream of side load refrigerant to cool the power storagemedium. Exemplary methods may further comprise storing at least aportion of the power in the power storage medium as back-up power.

The step of generating power may include providing power, which could besurplus power (beyond the power consumption of the adjacent poweruser(s)), to an electric grid. In exemplary embodiments, a portion ofthe stored power is used at the first location. Exemplary methods mayfurther comprise providing natural gas at the second location. Inexemplary methods, releasing power comprises pumping to pressure thepower storage medium, directing a working fluid in counterflow to thepower storage medium such that the working fluid warms the power storagemedium and the power storage medium condenses the working fluid,directing one or more gaseous products of combustion in counterflow tothe pumped-to-pressure power storage medium and to the pumped topressure working fluid, such that the gaseous products warm the twopumped to pressure fluids, and expanding those fluids ingenerator-loaded expanders.

In exemplary embodiments, an integrated electric grid, fuel source, andsurface system is provided comprising at least one power storagefacility at a first location, at least one distributed power generationfacility at a second location different than the first location, atleast one mobile power storage unit, and a fuel source in fluidcommunication with the distributed power generation facility. Inexemplary embodiments, the fuel source is a natural gas pipeline, but itcould be any fuel source. The power storage facility includes a powerstorage medium comprising liquid air, nitrogen, oxygen, or a combinationthereof, and the mobile stored power transportation unit is configuredto carry at least a portion of the power storage medium to thedistributed power generation facility via surface transport systems. Thedistributed power generation facility may be electrically connected toan electric grid. In exemplary embodiments, the power storage facilityis an air separation plant. The power storage facility may be configuredto use a portion of the stored power in a distributed power generationmode.

Exemplary embodiments include a method of engaging in a power exchangetransaction comprising storing power in a first location in a powerstorage medium, transporting at least a portion of the power storagemedium to a second location different than the first location, andexchanging at least a portion of the power stored in the power storagemedium. Exemplary embodiments include method of distributing powercomprising transporting power from a first location to a second locationin a power storage medium via a mode of transportation independent of anelectricity grid.

Advantageously, embodiments of the present disclosure eliminate the needfor an absorption chiller to recover heat-of-compression to producelow-grade refrigeration, which in other embodiments of VPS cooled theair streams prior to each stage of compression. This innovation reducesthe cost, size and weight of the inflow-to-storage equipment. In lieu ofan absorption chiller, exemplary embodiments use a “side load” oflow-grade refrigeration, which can be provided by the mechanical chillerthat also provides the deep refrigeration to the compressed air, priorto the air's expansion in a compressor-loaded turbo expander. The sideload is virtually “free” refrigeration, in that it is “surplus”(low-grade refrigeration) that is a normal byproduct of the mechanicalchiller, where the main purpose of that mechanical chiller is to providedeep refrigeration to the air liquefaction cycle and where the size andpower demand of that mechanical chiller need not be significantlyincreased in order to accommodate the low-grade refrigeration side load.In this context, “side load” can also include any recoverable low-graderefrigeration that may be available from the air separation plant (orother facility) that is adjacent to (or hosting) the power storageequipment.

Exemplary embodiments include methods of storing mechanical energycomprising compressing a power storage medium, providing side loadand/or main load (deep) refrigerant to cool the power storage medium,and separating the power storage medium into a product stream, e.g., O₂or N₂ and a recycle stream. The power storage medium can be air, orseparated constituents of air such as nitrogen, oxygen, or a combinationof nitrogen and oxygen. The recycle stream is directed such that itcombines with and is cooled by a stream of side load refrigerant andforms a refrigerant/recycle stream. The refrigerant/recycle stream isdirected in a first direction and the product stream is directed in asecond direction in counterflow to the refrigerant/recycle stream suchthat the product stream is cooled by the refrigerant/recycle stream. Thecooled product stream can then be stored in a dense phase, such as aliquid. Additional steps could include removing moisture and carbondioxide from the energy storage medium before liquefaction.

In exemplary embodiments, a method of releasing stored power comprisespumping to pressure a power storage medium, performing certain heatexchange steps, and expanding the power storage medium. The powerstorage medium can be air, or separated constituents of air such asnitrogen, oxygen, or a combination of nitrogen and oxygen. An exemplaryheat exchange step could be directing working fluid in counterflow tothe power storage medium such that the working fluid warms the powerstorage medium and the power storage medium condenses the working fluid.The working fluid could be condensed and pumped to pressure, heated andsent to a generator-loaded hot gas expander, all within a closed loop.Another exemplary heat exchange step could be directing the powerstorage medium in a first direction and directing hot air in a seconddirection in counterflow to the power storage medium such that the hotair warms the power storage medium. Another exemplary heat exchange stepcould be directing combustion gas in counterflow to the power storagemedium such that the combustion gas warms the power storage medium.

Advantageously, exemplary embodiments include the use of one or moregenerator-loaded gas turbines (GTs), which can provide the waste heatused to release the mechanical energy in the pumped-to-pressure L-Air orconstituents of air. By substituting a single GT for a combustionchamber, embodiments of the present disclosure can comfortably utilizethe (cooler) approximately 1,100° F. outflow stream from the GT. Forexample, a single GT, with a maximum 2.25 MW of output (achievable withcold inlet air), allows for the cost-effective and highly efficientdeployment of Commercial-Scale VPS units with about 14.4 MW/115 MWH ofoutput. Thus, exemplary embodiments further comprise directing gaseousproducts of combustion, such as exhaust, from a prime mover such as agas turbine in counterflow to the power storage medium such that theexhaust warms the power storage medium.

Exemplary embodiments further comprise matching an inlet air-flow rateof the prime mover to a selected storage capacity for the L-Air (orother power storage medium described herein). Exemplary embodimentsfurther comprise matching a first level of refrigeration content of theair to a second level of refrigeration content necessary to condense acounterflowing working fluid, recovering much of the cold contained inthe storage medium. The gaseous products of combustion such as exhaustcould be reheated such that the resulting heat matches the inlet air'sflow rate and a flow rate of the cold recovery working fluid. Moreparticularly, the amount of heat provided by the GT and possiblysupplemented with heat produced in an after-burner or supplementalheater, could be matched to the amount of L-Air stored during thenighttime inflow-to-storage mode and matched to the flow rate of theworking fluid in the secondary heat recovery loop of theoutflow-from-storage mode. In exemplary embodiments, pumped to pressureL-Air is matched to the flow rate of the working fluid, such that theexpanded working fluid is condensed by the outbound L-Air, ready forpumping to pressure, heated by a portion of the heat in the GT exhaust.

The inlet air-flow rate to the prime mover could be matched to a flowrate of the liquid oxygen, liquid nitrogen, or combination thereof suchthat the cold oxygen/nitrogen cool the inlet air to below ambienttemperatures, making that inlet air denser and improving the efficiencyof the GT. Exemplary embodiments further comprise matching a first levelof refrigeration content of the liquid oxygen, liquid nitrogen, orcombination thereof to a second level of refrigeration content necessaryto condense the working fluid. Exemplary embodiments further comprisereheating the exhaust such that the resulting heat matches the inlet airflow rate and a flow rate of working fluid. Exemplary embodimentsfurther comprise introducing methanol into the inlet air flowing intothe prime mover when that inlet air is cooled to less than 32° F. by thecold oxygen/nitrogen and/or by the cold working fluid.

In exemplary embodiments, a power storage system comprises a pluralityof compressors, at least one heat exchanger fluidly connected to atleast one of the compressors, at least one expander fluidly connected toat least one of the compressors, a mechanical chiller fluidly connectedto an expander, at least one valve, and a storage vessel fluidlyconnected to an expander. The compressors providing a plurality ofcompression stages to a power storage medium, which could be air orconstituents of air such as nitrogen, oxygen, or a combination ofnitrogen and oxygen. The mechanical chiller provides a main load (deeprefrigeration) and/or a side load of low-grade refrigeration to thepower storage medium. The valve separates the power storage medium intoa product stream and a recycle stream. The heat exchanger facilitatesheat exchange between the refrigerant/recycle stream and the productstream such that the product stream is cooled by the refrigerant/recyclestream. A clean-up assembly will remove the moisture and carbon dioxidein the inlet air to avoid freezing, and will be fluidly connected to atleast one of the compressors.

Exemplary embodiments include systems of power release and cold recoverycomprising a storage vessel, a pump fluidly connected to the storagevessel, a plurality of heat exchangers fluidly connected to the pump, atleast one expander fluidly connected to at least one of the heatexchangers and a prime mover assembly including a prime mover, the primemover assembly fluidly connected to at least one of the heat exchangers.The heat exchangers facilitate heat exchange between a power storagemedium and hot products of combustion such that the hot exhaust warmsthe power storage medium and the working fluid. In exemplaryembodiments, the prime mover is a gas turbine.

Accordingly, it is seen that systems and methods of semi-centralizedpower storage and distributed generation are provided. Disclosed systemsand methods provide power storage in a medium comprising L-Air, oxygen,nitrogen, or a combination thereof which can be transported todistributed sites for release of power during peak power demand periods(or other periods when power is needed). The disclosed systems andmethods further enable integration of the utility grid and other fuelsources such as gas pipelines so that customers for electric power andnatural gas can optimally take advantage of these two energy deliverysystems. These and other features and advantages will be appreciatedfrom review of the following detailed description, along with theaccompanying figures in which like reference numbers refer to like partsthroughout.

BRIEF DESCRIPTION OF THE DRAWINGS

The foregoing and other objects of the disclosure will be apparent uponconsideration of the following detailed description, taken inconjunction with the accompanying drawings, in which:

FIG. 1A is a box diagram of an exemplary embodiment of asemi-centralized power storage and power generation system and method inaccordance with the present disclosure;

FIG. 1B is a box diagram of an exemplary embodiment of asemi-centralized power storage and distributed generation system andmethod in accordance with the present disclosure;

FIG. 2 is a box diagram of an exemplary embodiment of a power storagesystem in accordance with the present disclosure;

FIG. 3 is a box diagram of an exemplary embodiment of a power releaseand cold recovery system in accordance with the present disclosure;

FIG. 4 is a box diagram of an exemplary embodiment of a power releaseand cold recovery system in accordance with the present disclosure;

FIG. 5 is a box diagram of an exemplary embodiment of a power releaseand cold recovery system in accordance with the present disclosure; and

FIG. 6 is a box diagram of an exemplary embodiment of a mobile powerrelease and cold recovery system in accordance with the presentdisclosure.

DETAILED DESCRIPTION

In the following paragraphs, embodiments will be described in detail byway of example with reference to the accompanying drawings, which arenot drawn to scale, and the illustrated components are not necessarilydrawn proportionately to one another. Throughout this description, theembodiments and examples shown should be considered as exemplars, ratherthan as limitations of the present disclosure. As used herein, the“present disclosure” refers to any one of the embodiments describedherein, and any equivalents. Furthemore, reference to various aspects ofthe disclosure throughout this document does not mean that all claimedembodiments or methods must include the referenced aspects.

In general, embodiments of the present disclosure are significant forseveral reasons. First, they provide alternatives to compressed air andliquid air storage media. Disclosed embodiments can function with liquidair, even at smaller, commercial-scales, but can also use liquid O₂ orliquid N₂ as the energy storage fluid. This offers opportunities tointegrate embodiments of the disclosure with existing and futureequipment at air separation plants and allows those plants to more fullyutilize O₂/N₂ that is made as byproduct of the other gas/liquidproduced, which has an existing customer base, but where that byproductis of low-value.

As described in more detail herein, in exemplary embodiments the O₂/N₂would be pumped to pressure by a cryogenic liquid pump, its cold contentrecovered by heat exchange with a working fluid loop (where therefrigeration content of the O₂/N₂ would condense/liquefy the workingfluid) and where the hot exhaust gas from a gas turbine (GT), or from agas-fired engine, would heat the pumped to pressure O₂/N₂ and workingfluid streams, which would be expanded in generator-loaded hot gasexpanders. The O₂/N₂ would be vented to the atmosphere (without harmfulemissions), and replaced the next night, and the working fluid would becontained in its own closed loop, which would be dormant during theoff-peak (nighttime) hours.

Exemplary embodiments allow the inflow to storage mode to occur suchthat an existing or newly constructed air separation plant is therecipient of that off-peak power, where that power is converted toO₂/N₂, and where the higher-value product is sold to existing or newlyestablished markets/customers and where the lower-value product is usedas the energy storage and release medium. In such embodiments the airseparation plant or other power storage facility uses disclosedembodiments at a commercial scale, likely fully using all of theavailable power output during the daily peak period but achievingsignificant capital cost savings (versus building a fullcommercial-scale VPS Cycle plant “from scratch”) because theinflow-to-storage mode is largely in place.

If O₂/N₂ is the storage medium, then any remaining low-graderefrigeration can be transferred (via heat exchangers) to the inlet airthat would noiiiially be drawn in by the GT, where, for example, −4° F.air is sent to the GT's inlet air nozzle. That approximately −4° F.inlet air can be the last stop of the stored L-Air during the outflowmode, if that is the medium of storage. That chilled inlet air couldalso receive an “infusion” of methanol (or other such “anti-freeze”fluid), such that the cold air's water content would not freeze and theanti-freeze fluid would combust, along with the air plus fuel in the GT.Absent embodiments of the present disclosure, the deliberate productionof such refrigeration to improve GT performance would not becost-effective.

Thus, disclosed systems and methods provide several major advantages.First, they advantageously eliminate reliance on L-Air as the storagemedium in favor or liquid O₂/N₂ storage, especially if that liquid O₂/N₂production unit is part of an air separation plant, where the existingequipment would allow the VPS deployment to avoid constructing theentire “inflow-to-storage” portion of the VPS Cycle. Only theoutflow-from-storage mode would need to be added to the air separationplant. In other words, exemplary embodiments allow each existing airseparation plant to become a cost-effective commercial-scale powerstorage and power production facility.

Second, they provide distributed power storage and production. Disclosedembodiments fill the gap in the distributed power production realm,above battery scales and below pumped hydro and other utility-scaleoptions. This is an important attribute because it allows each facilityto better match local power production and demand patterns and to allowfor relatively modest investments to achieve the intended goals of powerstorage. For example, a utility-scale power storage system may requireat least $100,000,000 of capital to deploy, while a commercial-scaleunit, such as per the present disclosure, may cost as little as$20,000,000.

Clearly, the lower “entry cost” of the commercial-scale deployments willmake it easier to advance power storage as an essential element of the“smart grid.”

Exemplary embodiments create a potential for every sizeable power-usingcustomer of the electric grid, where the customer is also on the naturalgas pipeline network, to become one of many distributed-power-storageand distributed-power-generating sites. (By “sizeable” we mean with apower demand of approximately 1 MW or more, over a 4-8-hour peak dailyperiod, for a total of 4-8 MWH.) Thus, for the first time in the historyof the overlapping power grid and natural gas (NG) pipeline network,many thousands of customers of those two (generally independent) systemscan “connect” the two energy delivery modes to store energy during lowpower-demand periods and to release that stored energy during highpower-demand periods, enhancing the service value and asset value ofboth the NG network and the electrical network, and substantiallyreducing the need for newly constructed, large-scale, distantly locatedpower plants.

A third major advantage is that exemplary embodiments providesemi-centralized power storage with distributed power generation. Theterm “semi-centralized” as used herein means the system is capable ofserving a plurality of off-site locations and can be deployed at lessthan utility-scale. Embodiments identify an entirely new set of“services” and “products” that can be provided by existing and futureair separation plants. For instance, semi-centralized power storagesites can convert electric power into mechanical energy, which producesa cryogenic storage medium (O₂/N₂), which can be transported to anothersite where the mechanical energy in the storage medium is recovered toproduce electric power. Each such plant can become a semi-centralizedsource of O₂/N₂ that can be delivered to decentralized, distributedpower generation sites, thus expanding the market for O₂/N₂ products andproviding a power storage service and a “power transport” service to theend users at the distributed power generating sites.

In effect, this also provides an alternative electrical transmissionsystem, whereby energy (originally in the form of electricity) istransported (in the form of a cryogenic storage medium) to a pointfurther “downstream” on the energy grid, or to locations beyond the gridor to mobile (rather than stationary) power release equipment. As such,embodiments of the present disclosure provide a means for avoiding theneed to pen⁻nit/site/build new power transmission systems, which todayare difficult to permit, politically controversial, and quite slow (ifever) to complete.

Exemplary embodiments allow the O₂/N₂ storage medium to be transportedto off-site distributed power (outflow mode) locations, thusgeographically separating the inflow to storage mode and outflow fromstorage modes. Such transporting of O₂/N₂ from its production source toa distributed power production site constitutes the transport of twosources of mechanical energy: one source is at the original power plant(including wind turbine) that sent its power down the grid to the airseparation plant, the second source is the mechanical energy input atthe air separation plant which converts the received electric energy(kW) back to the mechanical energy that produces the O₂/N₂.

In this embodiment the air separation plant acts as a regional (nearlyutility-scale) power receiving, converting and storage system, but sendsthe stored power (in the form of liquid O₂/N₂) to several off-site VPSoutflow mode locations that constitute distributed power generationsites. This embodiment allows the inflow-to-power mode to achieveeconomies of scale, but also achieve a wider “distribution” of the poweroutflow mode, connecting the two halves via highways, rail lines,waterways or other means of transporting the cryogenic energy storagemedium. Thus, the present embodiments identify a vast number of “energynodes” where the crossing of the (1) electric grid, (2) fuel sourcessuch as the natural gas pipeline network, and (3) the existing road,rail, or navigable waterway, air ways, system allows for the deploymentof commercial-scale, distributed power storage and distributed powerproduction facilities. Prior to the present disclosure those threenetworks, each a product of enormous prior investment, functioned mostlyindependently of each other without the benefits provided by the presentembodiments.

The O₂/N₂ production unit at any large air separation plant could serveoff-site VPS outflow mode equipment deployed in multiple locationswithin, e.g., 100 miles of the air separation plant, where no L-Air orO₂/N₂ production equipment would be deployed. Thus, the “inflow tostorage” part of this novel VPS model would be somewhat “centralized,”i.e., “semi-centralized,” at large, individual air separation plants,but at scales well-below utility-scale storage deployments. The“outflow-from-storage” that would be linked to each one of thosesemi-centralized storage facilities could be at many sites withintrucking (or rail or waterway delivery) distance of the O₂/N₂ (or L-Air)plant.

The reason O₂/N₂ would sometimes be shipped (instead of L-Air) is due tothe imbalance in the local market demand for O₂ or N₂ at each airseparation plant, where one of those products is sold in largequantities to an existing customer(s), but the other is a low-value“byproduct” of the air separation process. Air consists of about 23% O₂and 75% N₂ (by weight) with the remaining portion made of CO₂, argon,neon, hydrogen, helium, krypton and xenon, as well as some moisture.Thus, any air separation plant that is producing O₂ for sale to, e.g.,steel mills, glass manufacturing facilities or the health care industry,is also producing about three times as much N₂. Embodiments of thepresent disclosure substantially solve that imbalance by allowing theair separation plant to be the semi-central energy storage facility (forthe production of the cryogenic storage medium) from which manydecentralized power generation facilities are supplied by N₂. Inlocations where N₂ is the valuable commodity and o₂ is in surplus, O₂could be the cryogenic storage medium delivered to off-site distributedpower generation facilities.

Exemplary storage methods and systems advantageously separate (bypotentially hundreds of miles) the inflow to storage equipment at large,semi-centralized air separation plants, which have economies of scaleand the ability to receive large amounts of off-peak power from the grid(and which in many cases already exist), from many smaller distributedfacilities that would use most of the power generated during the peakhours at each such facility, with modest amounts of “left over” powersold to the local power grid during the daily peak period. Thus, thepower outflow mode could be widely distributed, and the distributedpower could be easily “absorbed” by existing grid. The “connection”between each hub and the various VPS outflow mode sites could bemultiple container deliveries of liquid O₂/N₂, by trucks on existinghighways, by rail car, by waterborne vessel, or other surface transportsystems or methods, or by other transport methods now known or futuredeveloped including airways, aerospace, and subsurface.

An NG pipeline network could deliver the NG used by the prime mover inthe outflow mode, and the same pipeline network could deliver NG to theair separation plant, which would produce LNG to fuel the trucks thatdeliver the O₂/N₂ to the off-site, decentralized, distributed powergeneration sites served. The production of LNG at air separation plantsis especially reasonable because the cryogenic process required toproduce LNG is very similar to the cryogenic process to produce L-Air,liquid oxygen and liquid nitrogen, all of which require similarfront-end water and CO₂ removal, multi-stage compression, deep-graderefrigeration, and storage/transport in similarly insulated cryogenictanks.

A fourth major advantage is that exemplary systems and methodsfacilitate transporting mechanical power outside, or independently of,the electric grid. Currently, “energy transport” is routinelyaccomplished by shipping fuel from one location to another. Examplesinclude the transport of NG in pipelines and the transport of LNG, coal,oil, and other fuels by ship, rail and trucks, where the fuelcontributes to the chemical process (combustion, oxidation, and energyrelease) that is the norm in all fossil-fueled power generation systems.On the other hand, the transporting of “refrigeration” in the form ofice had a long history that extended into the early 20^(th) century.Today, the transport of man-made ice, a product of mechanical energyinput, is no longer necessary or economically viable becauserefrigeration can be produced at the location where it is needed.Embodiments of the present disclosure seek to produce power where it isneeded but also allow some of the “mechanical” aspects of powerproduction to be transported from one site to another.

The production of power, or the enhancement of power production, bymechanical means is well understood, but up to now, has not been thesubject of “transporting” efforts. For example, it is well known thatinlet-air cooling of gas-fired turbines (GT) increases the density ofthe air “breathed” by the GT, thus reducing the mechanical load on theturbine's (front end) compressor. However, prior to disclosedembodiments there was no awareness in the power generation industry ofthe cost-effective possibilities for the “transport” such mechanicalenhancements to power production from one site to another. Until now,there was no practical way to transport significant mechanical energyfrom one location to another, say, 100-miles apart.

Exemplary embodiments use O₂/N₂, whichever has the lower value at anysemi-centralized air separation plant, as a mechanical energy transportmedium, allowing the “mechanical energy content” of that cryogenic fluidto be moved from a production site (e.g., the centralized air separationplant) to multiple, off-site, distributed power production facilities.Thus, the thermal fuel that drives those distributed power productionsites could arrive by standard transport mode (by NG pipeline, by LNGtrailer/rail car/ship, etc.) and the mechanical energy content thatwould enhance that site's power output would also arrive as O₂/N₂ bytrailer, rail car, or waterborne vessel.

The O₂/N₂ in this model is “transporting” the mechanical energy itreceived during the compression, liquefaction and distillation processat the air separation plant. Moreover, the off-peak power that drovethat mechanical process also contained mechanical input, especially ifthe power used to make the O₂/N₂ came from wind turbines, which senttheir mechanical energy down the electric grid to the air separationplant. Thus, the present disclosure facilitates, and allows for thefirst time), the cost-effective transport of mechanical energy outsideof the power grid.

Referring to FIGS. 1A and 1B, exemplary embodiments of a system ofsemi-centralized power storage and distributed power generation will nowbe described. An exemplary power storage and distributed generationsystem 101 a comprises at least one semi-centralized power storagefacility 100, which includes a power storage medium 104, which could beliquid air. The power storage facility 100 could be an air separationplant, in which case the power storage medium 104 could be liquid air orO₂/N₂ from the air being separated into its constituents. The powerstorage facility could also be located at a military/naval base,railroad yard or port, or at any “utility-scale” power storage and poweroutflow facility. In the exemplary embodiment illustrated in FIG. 1A thesemi-centralized power storage facility 100 is deployed where bothfunctions, i.e., inflow-to-storage and outflow-from-storage, occur atthe same facility.

The electric grid 110 receives off-peak power from at least one powerproducing site 102, including wind farms, solar farms, nuclear powerplant etc., and where that power is sent to power storage facility 100by way of the electric grid 110. It should be noted that off-peak powercould be produced at the power storage facility 100, e.g., in caseswhere the site has its own wind turbines, anaerobic digester or LFGsource, avoiding the need to receive (some or all) of the inflow tostorage power from the grid.

A power connection from the grid 110 could operate such that power isdelivered to power storage facility 100 during the off-peak period andstored there as L-Air or one of the other cryogenic storage fluidsmentioned in this disclosure and where power is used by the powerstorage facility 100 during the peak power demand period, with no powerleaving the site, and/or where any surplus power not required by thehost site 100 is sent to the grid during the peak period. Hence thepower 112 is shown as a double headed arrow “floating” with gaps at bothends, indicating that it is sometimes an “on” and sometimes an “off”connection between the grid 110 and the host site 100. Another fuelsource 120, which could be a natural gas grid, provides the fuel for theprime mover that operates during the power outflow mode, and which primemover provides the waste heat that enables the recovery of themechanical energy stored in the cryogenic storage fluid. Thus, asoutlined above the electric grid 110 and the natural gas grid 120 areintegrated at a single power storage and power production site that isnot just a “peaker” and is certainly not a large-scale power plant.However, the exemplary embodiment illustrated in FIG. 1A can beco-located with large-scale power plants, allowing the low-value,off-peak power production from such a plant to be stored for peak-periodrelease.

Referring to FIG. 1B, an exemplary power storage and distributedgeneration system 101 b comprises at least one power storage facility100, which could be an air separation plant, and includes power storagemedium 104, either air or O₂/N₂. The power storage facility 100 providesO₂/N₂ along transport routes 108 to several, off-site, distributed powergeneration facilities 106, which are at different locations than thepower storage facility 100. In exemplary embodiments, the power storagefacility 100 functions as an energy storage company (similar to today'senergy service companies (“ESCOs”)). The source of the power stored bythe power storage facility 100 can be multiple power producing sites 102which send their (off-peak) power to the power storage facility by wayof local connections 111 to the electric grid 110. The release of thestored power may occur at multiple, distant power release facilities 106that may use all or a portion of the power they generate for on-sitepower needs and/or send their surplus power the electric grid 110.

Those power producing facilities 102 may be “renewable” generationfacilities, such as wind farms, solar farms or landfill-gas-to-kW sites,or may be base-load power generation plants fired by coal or naturalgas, or nuclear power plants, all of which cannot fully turn down theiroff-peak power production at night, and are best served by sending theirpower output (at reduced prices) to distant power storage facilities100. As discussed in more detail herein, exemplary embodiments utilize asource of low-cost, off-peak power production (such as, but not limitedto, wind turbines), and a grid connection that can deliver that off-peakpower to the deployment sites of the present embodiments. That same gridconnection can take away any surplus power produced at the deploymentsite during the peak power demand period, which surplus power is notused by the host site.

In exemplary embodiments, the power storage facility 100 would be itsown “customer” for the stored power by releasing that power during thedaytime peak period as outlined throughout here. However, as an ESCO, aportion of the power storage medium could be transported by mobile powerstorage/transport units 130, such as truck, rail car or waterbornevessel or other surface transport systems, to distributed powergeneration facilities 106 where only the cryogenic storage medium(L-Air/O₂/N₂) storage tank and the outflow-from-storage equipment weredeployed, with no on-site cryogenic storage medium production capacity.Each one of those distributed power generation sites 106 could also beserved by any outside fuel source, including but not limited to NGpipeline 120, as could the air separation plant 100. Liquefied naturalgas (LNG) could fuel the mobile power storage/transport units 130 if theair separation plant 100 produced LNG in addition to its noinialproducts of air.

The link from the electric grid 110 to distributed power generation site106 is shown as “floating” arrows 112 because each site could receivenighttime power from the grid (to the extent it needed such off-peakpower) and would receive no (or reduced) power from the grid 110 duringthe daily peak power demand period. Moreover, because eachcommercial-scale deployment at distributed power generation sites 106would be a specifically sized, pre-engineered, modular “appliance,” theoutput of that power release equipment will often be greater than thevarious (and fluctuating) power demand requirements at each of theseveral sites 106 served by the ESCO.

In some measure the economic viability of such an ESCO network isdependent on the “affordability” of the pre-engineeredoutflow-from-storage appliances. The more modularity there is in eachdeployed outflow facility, and the larger the local, regional andinternational market for such deployments, the lower the cost of eachdeployment will likely be. Embodiments of the present disclosure inducethose conditions by allowing the “overcapacity” of each distributedpower generation (i.e., outflow) facility 106 to become a key element ofthe network illustrated by FIG. 1B. For example, if each of thedistributed power generation facilities 106 needs from 1 MW to 4 MW ofpower, than the same 5 MW, pre-engineered, modular version of theoutflow appliance would be deployed at each site, allowing the excessoutput from each distributed power generation site 106 to be sold by theESCO to the grid 110. In other words, each deployment at variousdistributed power generation sites 106 could be oversized, relative tothe customer's demand, such that excess power could be sold to the grid110 by the ESCO.

Thus, exemplary embodiments include the flow of surplus power 112 fromeach distributed power generation facility 106 back to the grid 110during peak power demand periods (or during other periods, as needed).In that way, the local grid can receive power from various distributedpower generation sites 106 and distribute that power, locally tofacilities that are not part of the ESCO network. Such localized powerproduction mitigates grid congestion, reduces line losses, allowsutilities to defer/avoid upgrades to their electrical distributionlines, and allows for an additional revenue stream to the ESCO. In turnthe multiple, single-sized deployments allow the ESCO to offer acompetitively priced service to each distributed power generation site106 and allows the ESCO to become a bigger customer of each of the 102power producers and a preferred customer of the 110 grid operator. TheESCO would be preferred because it is a steady client and providesimportant services that the grid operator does not provide.

The operator of the NG network 120 may or may not be the same entitythat operates the electric grid 110. In any event, the NG system 120benefits from the centralized power storage and distributed generationsystem by having a more distributed customer base, including the ESCO at100 and the various power outflow points at the distributed powergeneration facilities 106. Significantly, in multi-season locations,such as the US and Europe, much of the power storage and generation(outflow) issues covered by the present disclosure are most acute duringthe summer months when power demand is at its highest. Thus, the NGnetwork 120 is more fully utilized in the summer as a result of thepresent embodiments then it would be otherwise, yielding greater“capital efficiency” for the asset owners and rate-payers.

Furthermore, FIG. 1B shows the schematic confluence of the natural gasnetwork 120, the electric grid 112 as well as the road/rail/waterwaytransport route network 108 that cross each other in millions of pointsthroughout North America and Europe. Generally, the natural gas networkis below ground, the electric grid is mostly above ground, and theroad/rail/waterway network is between the two. The three systemssometime occupy the same “rights of way,” but often extend intoindependent (non-overlapping) networks. The present embodiments allowfor the comprehensive integration of those three networks at all thecrossing (confluence) points. At many thousands of such confluencepoints, or “nodes,” there exists a commercial, industrial, orcommunity-facility “customer” for electric power. In the absence ofembodiments of the present disclosure, that customer has very few (ifany) choices as to where and how that power is produced and how it isdelivered. Indeed, that customer is captive to the standard grid (whichis not a “Smart Grid” but a dumb one), where, for example, the customerincurs “demand charges” for use of power during the peak demand periods,and where the grid is “resistant” to the possibility of receiving powerfrom the customer.

By contrast, embodiments of the present disclosure open the door toinclude many thousands of such commercial, industrial orcommunity-facility power customers (e.g., with a need for 1 MW or moreof peak power) into the network illustrated by FIG. 1B. It is theconfluence of those three delivery systems—kW by the electric grid, BTUby the NG network, and stored mechanical energy by truck, or rail car,or barge—that allow embodiments of the present disclosure to up-end theexisting power production, (storage) and delivery system. (Storage is inparenthesis because the existing power system has virtually no storagecapacity.)

Embodiments of the present disclosure allow for the Smart Grid, beyondsoftware and metering improvements, by “requiring” that the electricgrid function in every possible direction (which it can) rather than inonly one direction, from the power plant to the customer. Thus, thesymbolic meaning of the double-headed, “floating” arrows shown on FIGS.1A and 1B is the multi-directional aspect of the grid, where virtuallyevery point on the grid can be as important as any other point. Thetruly Smart Grid will allow for the distributed power storage anddistributed power production embodiments of the present disclosure. Thepresent embodiments will also increase the viability of smaller ESCOs,creating competition for the less nimble, larger players in the powerindustry. Increased competition will result in lower prices; increaseddeliverability of energy produced from renewable sources; and generallyless emissions, despite the fact that each deployment site will have itsown fossil-fueled (NG) prime mover.

FIG. 1B yields at least one more embodiment. Each of the distributedpower production sites 106 may also include off-peak productioncapabilities, such as a single (appliance scale) wind turbine. Such adevice can send power back to the power storage facility 100 in the sameway that the air separation plant receives power from the various(distant) power production sites 102. This embodiment of FIG. 1B allowsfor small-scale, local deployments of renewable power generationsystems. Other examples might include power produced from the burning ofanaerobic digester gas at a sewage treatment plant or a dairy farm. Inall such cases, the off-peak power source can be quite small (a fewkilowatts) but would be relatively close to the air separation plant100, taking advantage of the local grid. At the extreme, such a modelwould allow every building, no matter how small, to host, for example, asingle (appliance scale) wind turbine, which would send its off-peakoutput to the semi-centralized power storage facility 100. That modelwould truly constitute a Smart Grid, because power (analogous toinformation) would be flowing in all direction to and from all locationsconnected to the grid. The present disclosure facilitates thatembodiment.

FIG. 2 illustrates an exemplary embodiment of an inflow mode for storageof mechanical energy using L-Air as the cryogenic storage medium. Forease of illustration, FIG. 2 shows sequential numbered points alongsteps of an exemplary process, with the same number at differentlocations on the figure representing the same point in the process. Thedisclosed inflow-to-storage mode eliminates the use of an absorptionchiller to inter- and after-cool the air streams as they move throughthe several stages of compression. Instead, the mechanical chiller thatprovides the relatively deep refrigeration required at theturbo-expander inlet will also provide a “side load” of low-graderefrigeration to inter- and after-cool the air that moves through themain compressor. The notations “P” and “R” correspond, respectively, toproduct air that is to be stored and refrigerant/recycle air that is therefrigerant air stream that liquefies the compressed product air.

An exemplary energy storage system 201 comprises a compressor array 200,which includes a plurality of compressors 200 a-200 g or compressorstages. At least one heat exchanger 202 is fluidly connected to at leastone of the compressors in the array 200. Exemplary embodiments employ aplurality of heat exchangers 202 a-202 g such that heat exchanger 202 bis fluidly connected to compressor 200 b, heat exchanger 202 c isfluidly connected to compressor 200 c, heat exchanger 202 d is fluidlyconnected to compressor 200 d, heat exchanger 202 f is fluidly connectedto compressor 200 f, and heat exchanger 202 g is fluidly connected tocompressor 200 g. At least one of the heat exchangers, 202 a in theillustrated embodiment, is fluidly connected to a cryogenic storagevessel 204. Exemplary systems further comprise at least one expander 206in fluid connection with the compressor array 200, in particular, withcompressor 200 g. A mechanical chiller 220 is fluidly connected to theexpander 206 and provides side load refrigerant 225 to the various heatexchangers the serve to inter- and after-cool the air that exits theseveral compression stages. Valves are used at various locationsthroughout the system, including valve 230, which serves to separate theair into a product stream (which becomes the power storage medium) andinto the recycle stream, as described herein.

In operation, the power storage medium 212 in the form of ambient air atapproximately 14.7 psia and at an average nighttime temperature of about53° F. enters point 1 and is compressed in compressor 200 a, the firststage of multi-stage compressor 200, here shown as a six-stage integralgear compressor. Other compressor configurations may also be selected,including two such integral gear compressors, one with two stages andone with four stages; as well as six stage reciprocating compressors(most suitable for smaller deployments of the present disclosure); andother variations of multi-stage compressors. It should be noted that thecompressor array 200 is shown in FIG. 2 as just one possibleconfiguration.

After the first stage of compression, the power storage medium, nowapproximately 40-psia air, with its temperature raised to about 242° F.,due to heat of compression, enters a clean-up assembly 210 including amolecular sieve 214 (or membrane or other similar device) where themoisture and CO₂ content of the air are removed so that no ice formslater on in the process. The molecular sieve design is well understoodby those in the gas processing industry and may include several vesselsthat contain an adsorbent such as zeolite, and which vessels operate ina programmed sequence. As the zeolite becomes saturated, that vessel is“swept” by clean sweep air 215 from another vessel, and that non-toxicsweep air, containing moisture and CO₂ is vented to the atmosphere. Thatsweeping (or regeneration) process may require heat input, which maycome from an electric warmer or from a natural gas fired heater. Thepresent disclosure is agnostic as to the most efficient method forremoving the moisture and CO₂ from the air. The air clean up assembly210 shows an exemplary arrangement of the multi-vessel molecular sieve214, an electric warmer 216, a sweep air vent 218 and a valve 221 thatseparates sweep air flow 215 from product air flow.

After the cleaning in the mole sieve 214 and after each stage ofcompression beyond the second stage, the heat of compression is removedby a first stream of low-grade refrigeration 225 provided as a side loadfrom the mechanical chiller 220, which will be described below. (Otherside load sources may include low-grade surplus refrigeration availableat the deployment site, for example from an air separation plant.)Returning to the several stages of compression, the inflow productstream 213 (which will be stored as the power storage medium 212) isjoined by recycle stream 232 in valve 228 after which that combinedstream enters the third compressor stage. Thus, a single compressorarray is compressing both the product stream and the refrigerant stream,because both of those streams are air free of CO₂ or moisture. Similarlyto valve 228 where those two streams are joined, the power storagemedium 212 is separated into product stream 213 and recycle stream 232by valve 230 at point 13, which is shown twice in FIG. 2 forillustration purposes, even though that point and valve only exist inthe singular. By that point in the compression process, after severalstages of compression, the combined product and refrigerant air streamis at approximately 500 psia.

A portion of the outflow from valve 230 is sent to compressor 200 g,which is the compressor-load on the cryogenic turbo-expander 206. As inall the other compression steps, the heat of compression is dissipatedin a heat exchanger by low-grade heat produced by the mechanical chiller220 or another source. The approximately 497-psia outflow from that heatexchanger is then sent to the mechanical chiller 220, where it is cooledto approximately −40° F. and then sent to expander 206 where thepressure of the refrigerant/recycle air stream 232 is reduced to about75 psia, thus cooling it to about −256° F. That deeply chilled air isthe refrigeration source that cools the other portion of the air (theproduct air stream 213) that left valve 230.

The refrigerant/recycle stream 232 and the product stream 213 move in acounter-flowing (opposing) manner through heat exchanger 202 a, which iswhere the product air stream 213 is “liquefied”, from inlet conditionsof about 50° F. at about 497.5 psia to outlet conditions of about −230°F. at about 496.5 psia. The valve 234 between heat exchanger 202 a andthe cryogenic storage tank 204 is a control flow valve. The storage tank204 is the same or similar storage tank that is shown in FIGS. 3-5,which illustrate exemplary outflow-from-storage modes. The storage tankmay also be a mobile version that transmits the stored energy tooff-site, distributed power production facilities.

It should be noted that in the paragraph above the quotation marksaround liquefied are used because that outflow product does notnecessarily need to be a true liquid. The present disclosure allows forthat product air stream 213, sent to storage tank 204 and stored as thepower storage medium 212, to be in a “metacritical” phase, such that itstemperature is colder than the air's critical temperature and itspressure is higher than the air's critical pressure. Such metacriticalair can be as dense as a true liquid (which can be defined as having atemperature colder than its critical temperature and a pressure that ishigher than its critical pressure), but will require less energy inputto achieve. Such metacritical air is dense enough to store in moderatepressure cryogenic storage tanks and dense enough to be pumped to ahigher-pressure (during the power outflow mode) by standard cryogenicliquid pumps. In other words, metacritical air will behave much likeliquid air, but require less refrigeration energy input to produce.

Turning to FIG. 3, exemplary embodiments of a system and method ofreleasing stored power will now be described. An exemplary system ofpower release and cold recovery 301 with L-Air (or metacritical air) asthe power storage medium 312 comprises a cryogenic storage vessel 304with a pump 302 driven by motor M, the pump 302 being fluidly connectedto the storage vessel 304. The system 301 further includes a pluralityof heat exchangers 306 a-306 f in fluid connection with the motor-drivenpump 302 and the storage tank 304. At least one expander 308 may includea plurality of expanders 308 a-308 d fluidly connected to at least oneof the heat exchangers 306 a-306 f. Exemplary embodiments utilize aprime mover assembly 303, e.g., a standard gas turbine (GT) array, toproduce a portion of the outflow power 329 and the heat source to warmthe working fluid loops, which consist of the primary air loop 310; andthe secondary (cold recovery) working fluid loop 320, where the workingfluid could be any suitable refrigerant, including but not limited toair, ammonia, suitable hydrocarbons, CO₂, or a combination thereof. Asillustrated on FIG. 3 power output 329 occurs in three locations, at theGT prime mover, at the air expanders, and at the working fluid expander.

In general, exemplary embodiments of power release and cold recoveryseek to more simply recover the refrigeration content of the cryogenicstorage medium. The present disclosure seeks to limit the cold energytransfer from the stored medium to only one other (secondary) workingfluid, and to use any remaining low-grade refrigeration in the storagemedium by cooling air and sending it at approximately −4° F. to the airintake of the GT that is the heat source in FIG. 3.

That cold air would be bone dry and absent of CO₂ because it wentthrough a mole sieve (or other such device) prior to its production as astorage medium. If O₂/N₂ were the refrigerated fluid that was warmed andexpanded in the VPS outflow mode, then any remaining low-graderefrigeration could be used to cool (to approximately −4° F.) the intakeair to the GT. As discussed below, in such embodiments methanol (or anyother similar alcohol) could be “spritzed” into the GT's intake air toprevent freezing of the moisture in the air. It should be noted thatanother cold recovery embodiment could transfer the cold content of thecryogenic storage medium to LNG or Cold Compressed Natural Gas (CCNG)production, thus substituting the LNG/CCNG production process for thesecondary working fluid cold recovery loop.

In operation, the stored L-Air 312 (or metacritical air) atapproximately −230° F. and 496.5 psia exits storage tank 304 and isfirst pumped to pressure in motor-driven cryogenic liquid pump 302, suchthat the air enters heat exchanger 306 a at about −222° F. and about1.715 psia. The cold outbound air condenses a counter-flowing stream ofworking fluid 314, which is in its own closed loop 320, as discussedbelow.

The air exits heat exchanger 306 a at about −200° F. and enters heatexchanger 306 b, where, along with a cold stream of working fluid 314,it cools the power storage medium 313, a counter-flowing, low-pressurestream of air, from about 420° F. to about −4° F. That low-pressure air,312 is the same air that is traveling toward additional heating andexpansion steps, but having been expanded and still containing residualheat. Thus heat exchanger 306 b is a heat and cold recovery device wherethe remaining heat content of the expanded air is used to pre-warm theoutbound air and the pre-expanded working fluid 314 and where therefrigeration content of those two streams is used to chill thelow-pressure air so that it can become cold dry inlet air to the GT'sfront-end compressor 324.

Returning to the power storage medium 312, high-pressure outflow airleaves heat exchanger 306 b at about 90° F., moves on to heat exchanger306 c (another heat recovery device) where returning working fluid 314at about 595° F. continues to pre-warm the air stream 312. The powerstorage medium 312 then moves to heat exchanger 306 d, where the hotgaseous products 316 of combustion from the GT 303, at temperaturesabout 1,100° F., warm the high-pressure air 312 to within nearlyten-degrees of the GT's exhaust 316 of about 1,100° F. The power storagemedium 312, hot, still high-pressure air, is expanded in a firstexpansion stage, expander 308 a, from about 1,710 psia to about 171psia, an approximately 10:1 expansion ratio. The expanded air leavesexpander 308 a at about 420° F., is reheated in heat exchanger 306 e bya counter-flowing stream of GT exhaust 316, and then expanded inexpander 308 b to an outlet pressure of about 17 psia, also about a 10:1expansion ratio. That last stage of expansion will yield an air streamat about 420° F., which, as mentioned above, is the heat source in heatexchanger 306 b. Other expander conditions (such as inlet and outlettemperatures and pressure letdown ratios) are possible.

Returning to the GT array 303, the NG fuel stream 318 moves to thecombustion chamber 322, and the cold, dry and dense inlet air streammoves through the front-end compressor 324 of the GT array 303, on tothe GT's combustion chamber 322 and then to the expander 308 d, which isloaded by generator 300. As outlined above, the main purpose of the GTis to provide the high-grade waste heat that warms the air and workingfluid streams. Its secondary purpose is to produce power output thatsupplements the power output recovered from the two-stage expansion ofthe air and the single stage expansion of the working fluid. The GT canalso generate back-up power if inbound electricity from the grid is notavailable (due to a power outage, natural disaster, terroristdisruption, etc.)

The temperature of the hot exhaust 316 from the GT (i.e., the gaseousproducts of combustion) will vary, depending on the efficiency of the GT(the more efficient the cooler the outflow); and on the inlettemperature of the air 313, where colder inlet air tends to yield cooleroutflow. Most GTs that are available within the range of, e.g., between100 kW to 5,000 kW (but other ranges are possible) will yield exhauststreams with temperatures of around 900° F. to 1,000° F., which ishigh-grade enough to yield “round-trip efficiencies” (RTEs) forembodiments of the present disclosure at more than 90%. However, severalwell understood “afterburner” or “duct burner” arrangements areavailable to allow a warmer GT exhaust to be sent to the air and workingfluid loops. Those familiar with thermodynamics and the optimalperformance of heat exchangers and hot gas expanders will be able toselect the appropriate post-combustion supplemental heating of the GTexhaust to yield the optimal temperatures.

Returning to the working fluid loop 320, after the working fluid 314 iscondensed in heat exchanger 306 a and collected in a buffer tank 326 atabout −30° F. and about 139 psia (depending on the selected workingfluid), it can be pumped to pressure by the same type of motor-driven,cryogenic liquid pump 302 as mentioned above for pumping the L-Air powerstorage medium 312. The liquid working fluid 314 is pumped to about1,710 psia and sent through heat exchanger 306 b, where it helps to coola counter-flowing stream of air 313 to about −4° F. (Colder inlettemperatures may also be possible.) The now about 90° F. working fluid312 is further heated in heat exchanger 306 f to about 1,000° F., andexpanded approximately at a 10:1 expansion ratio in generator-loadedexpander 308 c, exiting at about 171 psia and about 595° F.

The still warm working fluid 314 then moves through heat exchanger 306 cto help pre-warm the counter-flowing air, thus cooling the working fluid314 to about 100° F., before it enters heat exchanger 306 a forcondensation/liquefaction, completing the closed working fluid loop 320.It should be noted that the exemplary embodiment illustrated in FIG. 3constitutes an open loop for the air and NG streams and a closed loopfor the working fluid stream. The stored power storage medium 312,L-Air, leaves the system as GT exhaust 316 through flue 328. Electricityis produced by the GT's generator 300, by the generator(s) 300 thatloads the working fluid expander, and by the generator(s) 300 that loadthe air expanders.

By substituting a single GT for a stand-alone combustion chamber (whichwould produce hotter exhaust), embodiments of the present disclosure cancomfortably utilize the (cooler) approximately 1,100° F. outflow streamfrom the GT. For example, a single GT rated at 1 MW, but with a maximum2.25 MW of output (achievable with cold inlet air), allows for thecost-effective and highly efficient deployment of Commercial-Scale VPSunits with about 14.4 MW/115 MWH of total output. This advantageouslyprovides economic viability of VPS deployments at scales as small as kWscale and at about 1 MW, but where the prime mover can be a natural gasfired engine, rather than a GT.

At the 14.4 MW/115 MWH scale, hundreds or thousands of pre-engineered,factory-built, skid-mounted Commercial-Scale VPS units could be deployedannually in the US and globally, with each unit providing all or aportion of its power output to the host site, and with the surplusportion (if any) sold to the grid. In addition to the use of the GT toproduce some of the “distributed power” production, and thus providing areadily available high-enough-grade heat source (but a heat source thatis not too hot), the present disclosure offers the following: instead oftwo working fluid loops (e.g., CO₂ and NH₃) driven by waste heat, as inother VPS embodiments, the present embodiments eliminate the third (NH₃)loop and contemplate a variety of working fluids that can be substitutedfor CO₂.

In addition to condensing the closed loop working fluid, the outboundL-Air and the cold, pumped-to-pressure working fluid streams, cool theexpanded air, allowing that near atmospheric air to be sent to the GT asinlet air at −4° F., summer and winter in any climate. That last step inthe “cold recovery” process allows the GT to produce the 2.24 MWmentioned above, rather than only 1.5 MW (in the summer) to 2.0 MW (inthe winter) that it would normally produce. That yields a 12% to 49%increase in the power output of the GT, while making good use of theremaining low-grade refrigeration in the outbound L-Air.

In exemplary embodiments, power release systems and methods achieve anoptimal cold- and heat-recovery balance during the power outflow modeand an optimal balance between the fuel used by the prime mover and thefluids used by the system, to convert stored mechanical energy intodistributed power production. More particularly, the size of thecryogenic storage tank 304 and the flow rate of the power storage medium312 from the tank to the GT 303 can be “matched” to the cold air intakerate of a specific GT. In turn, the working fluid 314 flow rate can bematched to the refrigeration available from the outbound air (tocondense the working fluid) and the amount and grade of heat availablefrom the GT 303 to optimize the energy recovered at the hot air and hotworking fluid expanders which are generator-loaded.

In order to facilitate that balance, one point of “flexibility” withinexemplary systems is the amount and grade of the heat produced by the GT303, which can than correlate with the flow rate of the power storagemedium 312 and working fluid 314. As discussed above, that amount andgrade of heat can be controlled by including an after-burner orduct-burner in the GT array 303, and or by providing a supplementalheater to warm the air and/or working fluid streams. An afterburner 327or supplemental heater may benefit from the infusion of extra O2, whichwill result in a hotter combustion process. Within the limits ofcombustion chambers, heat exchangers, and hot gas expanders, suchhotter-than-standard products of combustion can enhance the outflowmode's performance. Thus, one final adjustment to the flow rates can beby way of NG flow rate to the GT and/or to the afterburner 327 and/or toa supplemental heater.

The following is an exemplary embodiment of such a balancing which canbe used with the system and method of FIG. 3 where the prime mover is aGT and the power storage medium is L-Air. First, the flow rate of theapproximately −4° F. air intake of the GT 300 is matched with theselected L-Air storage capacity. Also, the refrigeration content of thestored L-Air power storage medium 312 is matched with the refrigerationneeded to condense/liquefy the working fluid in closed loop 320 thatserves to re-use the available refrigeration in the stored L-Air tocondense the working fluid 314, allowing it to be pumped to pressure,warmed and expanded in a generator-loaded expander. Enough low-graderefrigeration is reserved to allow for the delivery of −4° F. air 313 tothe intake of the GT 303 where that low-grade refrigeration is recoveredfrom cold air 312 and working fluid 314 streams before they are heatedby the GT exhaust 316.

A portion of the heat content from the GT's approximately 1,000° F.exhaust is allocated to the pumped-to-pressure air, so that the storedenergy in the L-Air can be most effectively released. The remainder ofthe GT's hot exhaust heat content is allocated to the pumped-to-pressureworking fluid, whose flow rate (per the above) matches the flow rates ofthe L-Air 312 and GT exhaust gas 316. In the event that the availableheat from the GT exhaust is not quite enough, an NG-fired afterburner327 (or a direct-fired heater) is provided to the GT hot exhaust 316, toreheat that exhaust at an optimum point in the system, in order toproduce enough heat to match the L-Air and working fluid flow rates.

Thus, exemplary embodiments of the present disclosure could balance theflow rates of fuel to the prime mover with the flow rates of therefrigerated storage media with the flow of the working fluid, where theflow rates of the refrigerated storage media accounts for itsrefrigeration content relative to the condensation that is required forthe working fluid loop, and where any low-grade refrigeration thatremains in the cold fluids is fully utilized in the cycle. To achievethose balanced flow rates and heat and cold distributions, anafterburner or supplemental heater (with or without the use of extra O₂)can be integrated into the cycle.

However, for some deployments, that near-perfect balance of workingfluid flow rates, and heat and cold transfer, may not be cost-effective.In those instances, the present disclosure can be “reduced” to itssimplest embodiments. For example, the deployment of the exemplaryembodiments at an air separation plant will allow (if desired for thesake of simplicity) a single cryogenic fluid, e.g., air, to be pumped topressure, heated and expanded, without the working fluid loop, such thatany unused refrigeration in the L-Air may be used to pre-cool the inletto the GT and/or is used to produce more L-Air.

Similarly, if N₂ is the cryogenic fluid, e.g., at a laboratory, or foodpackaging plant, or at a military base, the use of the N₂ for otherpurposes by the host site may be the prime motivation for having liquidN₂ at that site. In such a context, the distributed power productionattributes of the present disclosure will be a welcome “bonus,” even ifthe refrigeration content of the N₂ is not fully recovered by thesecondary working fluid loop.

With reference to FIG. 4, exemplary systems and methods of power releaseand cold recovery using O₂/N₂ as the power storage medium 412 will nowbe described. An exemplary O₂/N₂ release system 401 would include thesame or similar components and configuration as the L-Air systemdescribed above in connection with FIG. 3. For instance, the systemcomprises cryogenic storage vessel 404 with a pump 402 driven by motor Mfluidly connected thereto, a plurality of heat exchangers 406 a-406 f influid connection with the pump 402 and the storage tank 404, and atleast one expander 408, which may include a plurality of expanders 408a-408 d, fluidly connected to at least one of the heat exchangers 406a-406 f. Exemplary embodiments would also utilize a prime mover assembly403, e.g., a GT array including GT and generator 400, to produce aportion of the outflow power 429 and as the heat source to warm theworking fluid loops (e.g., air and CO₂); the primary O₂/N₂ loop 410; thesecondary (cold recovery) working fluid loop 420. Aside from the use ofO₂/N₂ as the power storage medium and the differences mentioned below,the other components, loops, and streams 412, 413, 414, 416, 418, 420,422, 424, 426, 428, 430 are analogous to the corresponding itemsdesignated by the 300 series in FIG. 3. Generators 400 are shown inthree locations, loading the GT 403, the air expanders 408 b and 408 cand loading the working fluid expander 408 c. Power output 429 occurs atall three of those locations.

One variation when using O₂/N₂ as the power storage medium 412 is thatthe intake air 413 to the GT array 403 is ambient air that is cooled inheat exchanger 406 b by the remaining low-grade refrigeration in theO₂/N₂, and exemplary systems and methods further comprise a methanolinfusion system 460. The methanol infusion system 460 provides methanol461 (or other suitable and combustible anti-freeze) from tank 464, whichis pumped to appropriate pressure by pump 466 and infused to the inletair via a spray valve 462 to keep the water content in the inlet airfrom freezing. The methanol infusion step would occur at/near point A,prior to the air's entry into heat exchanger 406 b. The methanol (orother combustible anti-freeze) would be replenished periodically, asneeded.

As discussed above, power release systems and methods achieve an optimalcold- and heat-recovery balance during the power outflow mode and anoptimal balance between the fuel used by the prime mover and the fluidsused by the system, to convert stored mechanical energy into distributedpower production. An exemplary embodiment of that balancing effort wherethe prime mover is a GT and the power storage medium is liquid O₂/N₂ isas follows. First, the flow rate of the stored power storage medium 412,liquid O₂/N₂, is matched to the inlet air flow rate of the GT array 403such that the outflowing O₂/N₂ 412 will cool the entire ambient inletair 413 to the GT down to approximately −4° F. The infusion rate of themethanol 461 used to prevent freezing of the cooled inlet air 413 ismatched to the flow rate of the inlet air stream 413 and to its watercontent.

The refrigeration content of the stored O₂/N₂ 412 is also matched withthe refrigeration needed to condense/liquefy the working fluid closedloop 416 that serves to re-use the available refrigeration in the storedO₂/N₂ 412 to condense the working fluid 414, allowing it to be pumped topressure, warmed and expanded in a generator-loaded expander. A portionof the heat content from the GT's approximately 1,000° F. exhaust isallocated to the pumped-to-pressure O₂/N₂ so that the stored energy inthe O₂/N₂ can be most effectively released. The remainder of the GT'shot exhaust heat content is allocated to the pumped-to-pressure workingfluid, whose flow rate matches the flow rates of the O₂/N₂ and GTexhaust gas. In the event that the available heat from the GT exhaust isnot quite enough, an NG-fired afterburner 427 (or a direct-fired heater)may be provided to the GT hot exhaust 416, to reheat that exhaust at anoptimum point in the system, in order to produce enough heat to matchthe L-Air and working fluid flow rates.

It should be noted that this exemplary balancing process can be modifiedif the power output mode is located at an air separation plant, alongwith the power storage (liquid O₂/N₂) production mode. In that event,the process can be simplified, eliminating the working fluid loop, andallowing any remaining refrigeration in the outbound O₂/N₂ stream to beused by the air separation plant to produce more liquid air and more ofthe higher-value liquid O₂/N₂ that is sold to the market. Thatsimplification will reduce the capital costs of the power outflow mode,simplify its operation, and allow for the proper matching of availableheat and cold so that no useful energy is thrown away. Also, thebalancing can be achieved by using any remaining cold in the outboundstorage medium to produce LNG/CCNG.

FIG. 5 illustrates another variation where an NG-fired engine 500replaces the GT 403. In exemplary embodiments, heat of about 1,000° F.for outflow mode may be provided by burning of fossil fuel such asnatural gas. Other similar fuels, such as anaerobic digester gas, orlandfill gas, or other biogases can also be used. With an NG-firedengine as the prime mover, the engine will also benefit from chilledinlet air. The waste heat flow from the engine (including by use of anafterburner or supplemental heater) can be calibrated against theoutflow rate of the stored L-Air (or liquid O₂/N₂) and the cold recoveryachieved by the working fluid loop. The refrigeration content of thestorage medium could be matched to the condensation required by anappropriate flow rate of the working fluid in its loop, where both ofthose streams are heated to about 1,000° F., which is an optimaltemperature for expanding those previously pumped-to-pressure fluids ingenerator-loaded hot gas expanders. The cold content of the outboundcryogenic storage fluid 512 is recovered in heat exchanger 506 b wherethe inlet air 513 to the engine is pre-cooled to approximately 34° F.,avoiding the freezing of the water content of the air.

An exemplary O₂/N₂ release system 501 would include the same or similarcomponents and configuration as the L-Air system described above inconnection with FIG. 4. For instance, the system comprises cryogenicstorage vessel 504 with a pump 502 driven by motor M fluidly connectedthereto, a plurality of heat exchangers 506 a-506 f in fluid connectionwith the pump 502 and the storage tank 504, and at least one expander508, which may include a plurality of expanders 508 a-508 d, fluidlyconnected to at least one of the heat exchangers 506 a-506 f. Exemplaryembodiments would also utilize a prime mover assembly 503, e.g., in thiscase including NG-fired engine 505, to produce a portion of the outflowpower 529 and as the heat source to warm the working fluid loops (e.g.,air, CO₂ or other fluids mentioned above); the primary O₂/N₂ loop 512;the secondary (cold recovery) working fluid loop 520. Aside from the useof an NG-fired engine instead of a GT and the differences mentionedbelow, the other components, loops, and streams 512, 513, 514, 516, 518,520, 522, 524, 526, 528, 530 are analogous to the corresponding itemsdesigned by the 400 series in FIG. 4. Generators 500 are shown in threelocations, loading the engine 503, the air expanders 508 a and 508 b andloading the working fluid expander 508 c. Power output 529 may occur atall three of those locations.

This embodiment may include an “after-burner” or a supplemental heater(not shown), which would raise the temperature of the engine's exhaustto about 1,100° F., providing the optimal-grade heat to the system. Inthis exemplary embodiment, the cryogenic storage medium (L-Air or O₂ orN₂) 512 would not be sent to the engine 500 but would be vented to theatmosphere as a harmless outflow stream.

However, the cold content of the power storage medium 512 and theworking fluid stream 514 are used to cool the inlet air 513 to theNG-fired engine 505, providing the engine 505 with denser air(containing more oxygen per volume), and allowing the engine to performbetter, in a steady manner during all seasons. To the extent that thecold content of the outbound cryogenic power storage medium 512 and theworking fluid 514 (traveling in its closed loop) exceeds therefrigeration that can be applied to the inlet air 513, any surplusrefrigeration may be used in an adjacent process, such as foodprocessing, or for summer cooling of a building or for LNG/CCNGproduction. Additional uses for such surplus refrigeration may includethe cooling of the generators that load the engine and the expanders,improving the efficiency of the generators. FIG. 5 does not show thosecold recovery options, which are well understood by process engineers.

In exemplary embodiments, an approximately 5 MW/40 MWH VPS design coulduse a 1 MW natural-gas-fired engine as the prime mover instead of theGT. As in the above example that used a GT and was scaled at about 14.4MW/115 MWH, the amount and grade of the waste heat produced by theengine could be matched to the amount of stored L-Air (or O₂/N₂available at an air separation plant) and to the working fluid flow ratein the second loop. The total heat available from the 1 MW engine, thelower-grade of that heat, and the fact that the waste heat is splitbetween the engine's water jacket and its exhaust stack, suggests thatan afterburner may be useful in attaining the optimal amount and gradeof heat (around 1,000° F.) from the engine.

At this scale, a stand-alone inflow-to-storage and outflow-from-storagefacility could contain several reciprocating compressors for dealingwith the inlet air, all on a single skid, with a second skid containingthe gas-fired engine, a third skid containing the mechanical chiller andheat exchangers, and a fourth skid containing the hot gas expanders.Such a 4-skid configuration would be the “appliance scale” version ofthe present embodiments, where the inflow and outflow modes of thepresent invention were at the same location. That scale would allow fora “factory-built” configuration (rather than field constructed),allowing a single (or several, pre-engineered design(s) to be widelydeployed. Furthermore, for those customers that only need about 3-4 MW(24-31 MWH) of power output, the pre-engineered VPS “appliance” wouldstill be a viable deployment option because any surplus power outputfrom the appliance, above and beyond the host customer's needs, could besold to other customers on the same electric grid that delivered theoff-peak power to the appliance.

Turning to FIG. 6, another exemplary embodiment of a power release andcold recovery system 601 could be a mobile (rather than stationary)deployment of the power outflow mode for vehicle propulsion, where thepumped to pressure power storage medium 612, e.g., liquid nitrogen orliquid air, is heated by waste heat 616 from an LNG fueled,electricity-producing locomotive's (or ship's or other vehicle's)turbine 603. (We envision a GT because it is generally lighter andrequires less maintenance than engines.) The LNG-fueled GT 603 couldprovide about 20% of the total output of the “combined cycle” powerplant, with the remaining 80% derived from the mechanical energy storedin a separate container of liquid air, where that energy would bereleased by the recovered hot products of combustion 616 that isproduced by the GT 603, and where a portion of the refrigeration contentof the power storage medium 612 is used to deeply chill the inlet airstream to the GT's front-end compressor 624, thus improving itsperfonnance. That configuration can be called a “hybrid-electric cycle,”but where the GT does not drive the vehicle, but rather contributeselectric power output (along with the hot, high-pressure air), wherethat combined electric output drives motors that drive the locomotive'swheels or the ship's propellers.

Such embodiments would include the same or similar components andconfiguration as the system described above in connection with FIG. 5.For instance, the system comprises cryogenic storage vessel 604 with apump 602 fluidly connected thereto, a plurality of heat exchangers 606a-406 c in fluid connection with the pump 602 and the storage tank 604,and at least one expander 608, which may include a plurality ofexpanders 608 a-608 c, fluidly connected to at least one of the heatexchangers 606 a-406 c. Aside from the use of a locomotive or shipturbine, and the differences mentioned herein, the other components,loops, and streams 612, 614, 616, 624, 628, are analogous to thecorresponding items designed by the 500 series in FIG. 5. Generators 600are shown in two locations, loading the GT 603, and the expanders 608 aand 608 b. Power output 629 occurs at those two locations.

The locomotive (or other vehicle) could be served by one or more LNG“tenders” 660 (tank cars) and by one or more L-Air tenders 604. Theproduction of LNG and L-Air could occur along the rail line (or othertransportation route), using NG pipelines along the rail line as thefeed gas for the LNG 618 and ambient air as the feed for the integratedL-Air plant. (The equipment and general principles of LNG and L-Airproduction are similar and can be integrated symbiotically.) Such acombined LNG and L-Air plant could use “wheeled” renewable power duringits nighttime operations, per the inflow-to-storage mode of the presentdisclosure. Each such plant could be a fully functioning distributedpower storage and distributed power generation facility. However,instead of sending peak power out on the grid, the peak period poweroutput would allow the plant to operate off-grid during the daytime.Moreover, the plant's two products, LNG 618 and L-Air 612 wouldconstitute “transportable,” stored mechanical energy assets. In the caseof the LNG, the energy content is mostly in the potential release of theBTU content of the NG as it undergoes the chemical changes associatedwith combustion. In the case of the L-Air, the stored energy is releasedin a mechanical manner as the pumped-to-pressure power storage medium612, e.g., L-Air, is vaporized, heated and expanded in agenerator-loaded hot gas expander 608 a, 608 b.

Multiples of such plants (operating as power storage and powergeneration facilities 601) can serve multiple locomotives, each of whichbecomes part of the distributed power production network. Of course,similar embodiments can be applied to ships, where the LNG and L-Airplant is located at ports. Beyond that, there is potential to use thisembodiment for heavy-duty mining equipment, and for trucks, buses, orother vehicles, especially if they are part of a fleet that returns to abase depot for daily fueling, where both LNG and L-Air are available.

Though Commercial-Scale VPS plants can be deployed at virtually anylarge industrial facility, among the “lowest-hanging fruit” are airseparation plants that operate 24/7, have on-site L-Air productionequipment, and could consume a large portion of the above exemplifiedembodiment where 14.4 MW/115 MWH of power is produced. The entire inflowmode (producing L-Air) already exists at each air separation plant,mostly eliminating the VPS inflow-to-storage equipment, thus reducingthe complexity, capital cost and the footprint of each VPS deployment.

Moreover, many air separation plants have an imbalance between theirliquid O₂ and N₂ production rates, because they are often located at“host” sites that want only one of those products, not both. Disclosedembodiments can utilize stored liquid O₂ or liquid N₂ (instead ofL-Air), where the stored (low-value) cryogenic liquid could be sentthrough the outflow-from-storage mode outlined above, but without beingsent to the GT. Instead, any remaining refrigeration in the O₂ or N₂ isused to cool the inlet air to the GT, after which the O₂/N₂ is vented atambient temperature and pressure, making room for more O₂/N₂ storageduring the next nighttime off-peak period. (Of course, the venting ofclean O₂/N₂ is not an emissions issue.)

A further optimization that is likely deployable at air separationplants, would simplify the outflow mode to just the GT and an open loophot air (or O₂/N₂) expansion cycle, without the secondary working fluidloop. The flow rate of the stored L-Air/O₂/N₂ could be matched to theavailable heat from the GT, and the air separation process functioningadjacent to the VPS deployment could recover any excess refrigerationavailable from the pumped-to-pressure L-Air/O₂/N₂. That optimizationwould be the least complex, least costly, and yield the smallestpossible footprint, and can very efficiently yield well above 10 MW/80MWH of total power output with a single GT unit and a single(two-stage-with-reheat) generator-loaded hot gas expander.

The configuration outlined above (where semi-centrally produced liquidO₂ or N₂ is received by a decentralized power generation network) can beinstalled at numerous off-site customer locations, say, within a100-mile radius of any air separation plant. In such embodiments, eachcustomer's storage tank and outflow equipment would receive daily O₂/N₂deliveries from a semi-central air separation plant, thus avoiding about35% of the capital cost of a fully independent VPS Cycle plant at eachcustomer's site. The semi-centralized air separation plant would, ineffect, be the utility-scale “power storage” facility, producingbulk-scale O₂/N₂, while the satellite sites, with only cryogenic storageand VPS outflow mode equipment, would constitute a commercial-scalenetwork of distributed power generation/power release sites. Thedelivered price of the O₂/N₂ would typically need to be competitive withthe cost of L-Air produced by each customer if each one would haveinstalled its own VPS inflow-to-storage facility and used that equipmentwith off-peak power purchased from the grid. That competitive pricestructure can likely be attained because of the economies of scale atthe air separation plant and because the O₂ or N₂ that is the storagemedium is the lowest-value product of the air separation plant.

Further to the role of air separation plants, deployments of disclosedembodiments at any air separation plant could cause that facility tooperate as an ESCO, opening up an entirely new business opportunity tothe air separation industry. At the simplest level, each air separationplant would utilize the systems and methods of the present embodimentsto receive and store off-peak power and to release that power during thedaytime peak demand period, allowing it to be entirely off the gridduring the daytime. In that model, the air separation plan would beacting as an ESCO for itself, and possibly selling surplus power to thegrid. When an air separation plant is located at a “host” site, such asa steel mill or glass manufacturing facility, to which it provides, forexample, O₂, it can now be the ESCO to that host entity as well as toitself.

In the semi-centralized models outlined herein, the air separation plantcan act as the ESCO for the several power-outflow (distributed powerproduction) sites that it would be supplying with O₂/N₂, except that inthat case the ESCO would not be selling power but selling stored energyin the form of a cryogenic fluid. In the context of the products andservices provided by air separation plants, the ESCO role may be asimportant as the current (standard) products. As such, the ESCO role maystimulate new air separation plant deployment (business growth), wherethe standard products/services (O₂, N₂, CO₂, argon . . . ) are lucrative“byproducts” of the ESCO function.

In all of the embodiments discussed herein, the prime mover can continueto generate power (e.g., 1 MW from a single GT or 1 MW from a singleengine) at the VPS distributed generation facility even if the grid is“down” for hours/days/weeks/months, and no new L-Air (or O₂/N₂) can beproduced, stored or delivered. As long as the NG pipeline system isintact, each VPS plant could have about 10% to 20% of its rated poweroutflow capacity available as back-up generation. Thus, disclosedembodiments are not only distributed power storage and distributed powergeneration methods and systems, they are also methods for providingbackup power to the host site, allowing disclosed embodiments to replacediesel generators (and their fuel tanks) and other types of backuppower, and allowing that rarely used backup capacity to have a full time(daily) purpose.

Moreover, some “mission-critical” facilities that have a very lowtolerance for power outages, such as military bases, hospitals and datacenters, may opt for “extra” on-site N₂ (or L-Air or O₂) storage,allowing them to continue to produce power, at the full capacity of theVPS deployment, as long as the NG pipeline is not disrupted and for asmany hours as the stored N₂ (or L-Air or O₂) allows. Many military basesrely on N₂ as the gas that fills tires on trucks and airplanes, because,unlike air, N₂ contains no oxygen and does not support fires. Disclosedembodiments allow such on-site N₂ plants (or N₂ storage tanks, if the N₂is delivered from off-site producers) to be integrated into acomprehensive distributed power storage, distributed power production,and emergency back up power system.

The distributed power production embodiments discussed throughout thepresent disclosure are not only a supplement to centralized powerproduction, but also an alternative to it. Exemplary embodiments offeran entirely new model for the production and distribution of power,substantially eliminating the need for “big” power plants (with 100s ofMW of power output capacity) and allowing for a substantially reimaginedgrid.

For reasons related to air emissions and ash treatment and theassociated costs of mitigating those impacts of coal-fired power plants,there are not likely to be any new coal-fired power plants built in theUS or in Europe. Thus, the options for building new “big” power plants(with 100s of MW of capacity) that use a low-cost fuel (coal) will besignificantly reduced. The low-cost of coal is due in large measure tothe fact that the externalities of its emissions are not “paid for” bycoal-fired generators and to how it is removed from the earth. If thosecosts were reflected in its price, it would not necessarily be thelowest-cost fossil fuel.

The possibility of substituting nuclear power plants for coal fired onesis remote because of public resistance to nuclear plants, their expense,and the long lead-time required and the absence of viable nuclear wastedisposal system. Small-scale nuclear power plants are in development,but their acceptance by the public is not assured and theircost-effectiveness has not yet been demonstrated. Building new nuclearpower plants once held the promise of zero air emissions (and no ashproduction), but the issues related to nuclear waste disposal and“perceived” (or real) questions surrounding safety have not been solved.

Most observers will point to NG-fired combined cycle power plants as theonly viable alternative to meeting long-term power demand (especiallybaseload demand) in the US and Europe. Such plants offer the cleanestfossil fuel option and rely on a relatively low cost fuel. However, bigcombined cycle power plants need to be located on regional NG pipelinesthat can deliver the required amount of fuel, and near large quantitiesof readily available, low-cost water to feed the cooling towers and thesteam side of the cycle. Their cost, at hundreds of millions of dollars,requires a large customer base (prior to construction), and access to alarge amount of capital.

When accounting for the site selection, permitting process, the need toobtain capital commitments, and the need to construct each combinedcycle power plant as a “one-off” with long lead times for highlyspecialized equipment, the time between a proposed deployment and theplant's start up and commissioning can take many years. Despite theirscale, big combined cycle power plants, including the largest, newestones, with the most sophisticated components, do not achieveefficiencies higher than approximately 60%. In addition to the above,large-scale, centralized combined cycle power plants requirelarge-scale, complex, long-distance power transmission systems, whichalso take years to permit and construct (if they get permitted at all).Both the centralized power plants and the long-distance transmissionsystems are vulnerable to natural and man-made events.

In summary, such big combined cycle power plants are almost always farfrom their customers, use large quantities of precious water, requirevery large investments of capital and time, typically must “pre-sell”their power to a large customer base, offer not especially highefficiencies, considering their scale, and (along with the complex gridthat connects them to their large customer base) are vulnerable tounplanned events and disasters.

The growth of renewable power generation (such as from wind turbines) isa significant and commendable trend for various reasons, including theability to avoid emissions, avoid radioactive waste, and avoid theentire process associated with finding fuel sources, recovering thefuel, processing it, transporting it and storing it. However, the growthof the renewable power sector is not fast enough to keep up withworldwide power demand and the intermittency of most renewable power isa significant limitation. In short, if the renewable power sector is togrow to its full potential, power storage must grow with it. Theinventor's prior patents in this realm may help, as will the presentdisclosure.

Most landfill sites produce landfill gas (LFG) that, after rudimentarycleaning, can be burned in engines (or turbines) to produce electricity.This approach is in lieu of flaring of LFG, thus converting a “renewableresource” (trash) into energy. However, the value of nighttime powerfrom such LFG-to-kW deployments is lower than the daytime value.Embodiments of the present disclosure allow that nighttime power to beconverted to stored L-Air (or other cryogenic fluid), which would bereleased as extra power during the daytime, where the waste heat fromthe existing engine (or turbine) would drive the power outflow mode. Asimilar arrangement can be integrated with anaerobic digesterfacilities. Instead of flaring the digester gas, the present disclosurewill allow that gas to be used as a nighttime fuel for the production ofL-Air, and as a daytime heat source for the release of the stored L-Air.

Embodiments of the present disclosure allow many small distributed powerproduction facilities to be deployed on almost any NG pipeline; close totheir customers; requiring very little (if any) water; requiring smallerinvestments of capital and time to deploy; without requiring a largecustomer base that needs to be contracted prior to deployment; achievingapproximately the same efficiency as much large combined cycle powerplants; and reducing the “vulnerability” of the entire power productionand distribution system.

Moreover, each deployment of embodiments of the present disclosure,whether as a stand-alone power storage and power production facility, oras part of the semi-centralized storage model outlined above, will allowfor “receiving” off-peak renewable energy from sources such as windfarms. That feature will facilitate a more widespread deployment ofrenewable power production sources, allowing them to be betterintegrated with the power grid by delivering baseload, dispatchablepower to consumers of electricity. At the same time, the growth of therenewable power sector will enhance the need for the presentembodiments.

New York City's (NYC) daily power demand is among the largest in the USwhen measured by the geographic size of the City. At the same time, theability to provide in-City power generation plants is severely limitedfor many reasons, including the need to avoid new “point source”emissions. The construction of new high-capacity cables from outside theCity is equally challenging and very expensive. In the absence of newin-City power generation and/or the construction or upgrading of thegrid that delivers power to the City, the City will experience powerdemand that exceeds the capacity of the grid, especially during summer.

Exemplary embodiments of the present disclosure offer several plausibleresponses (for NYC and elsewhere, globally). Peaker Plants: NYC andnearby Long Island host a number of simple cycle 40 MW peaker GTs, whichwere installed to alleviate a shortage of available power during peakdemand periods. Each one of those sites is suitable for enhancement ,where the cryogenic N₂ (or O₂ or L-Air) tank(s) would be deployed alongwith the remainder of the VPS outflow mode equipment, but without theinflow-to-storage equipment. The N₂ used in such an upgrade would arriveon a daily or semi-weekly basis, preferably at night to avoid trafficissues. A single air separation plant in or near NYC (or Long Island)would service several such distributed VPS deployments. In this context,with sites that do not have a lot of room for new equipment, and wherethe economic value of the newly produced power is quite high,embodiments may not need to include the working fluid loop. Instead thecold content of the N₂ would only be used to pre-cool the inlet air tothe GT. Such a simplified design may be less efficient than the one thatincludes the working fluid cold recovery loop, but it may be thepreferred choice given space limitations for deployment, or wherereduced capital cost is more important than operating efficiencies.

Con Edison Steam System: Exemplary embodiments allow the grade of heatavailable to be adjusted by using supplemental heat. In the context ofNYC, where new “point source” emission permits are difficult to obtain,such a supplemental heater would be installed in tandem with some(on-going) reduction of steam generation in Con Edison's existingCity-wide “district heating” system. In other words, Con Edison'sdeclining steam customer base would allow it to switch a portion of itsannual fuel use from steam production to the supplemental heating of theworking fluids used in the present embodiments, resulting in no newemissions. By relying on an off-site (semi-centralized) air separationplant for the daily deliveries of N₂, each deployment would avoid theneed to build the front-end, inflow-to-storage equipment, reducing thefootprint of the deployment and reducing its complexity at the“customer's” site. In summary, the present embodiments, when deployed intwo distinct segments (centralized power storage and de-centralizedpower release), will allow Con Edison's steam generating facilities tohave a newly productive mission, and allow, for the first time in manyyears, for NYC to deploy new power production equipment within the Citylimits (with no new emissions).

In-City air separation plants: Per the above, NYC and nearby Long Islandand Westchester would now be ripe for newly constructed air separationplants. Those plants would not only serve the various decentralized(distributed generation) power production sites, but would also provideliquid oxygen to the large health care market (and other O₂ markets) inthe NYC region. The closer those new air separation plants can belocated to the various VPS power generation sites, the lower thetransportation costs of the cryogenic fluid from the semi-centralizedplant(s). As mentioned above, the integration of LNG production withL-N₂ production is a relatively simple matter. In the context of NewYork (outside of NYC) an air separation plant that produced L-N₂ for useat nearby VPS outflow-from-storage deployments could also produce LNG.That LNG could be used to fuel the trucks that deliver the L-N₂. Ofcourse, the air separation plant itself could also be a VPSoutflow-deployment site, using stored N₂/O₂ produced the night before asits working fluid during the peak daytime period when the plant could gooff the grid (in whole or in part).

Organic Rankine Cycle (ORC) systems convert waste heat to energy in acycle that is analogous to the steam portion of a combined cycle powerplant and to the outflow mode of the present embodiments. However, mostcommercially available ORC systems require relatively high-grade heat(above 300° F.) to operate. Moreover, even when the grade of heat isabove 600° F. (as preferred by some ORC systems) the efficiency of ORCsystems tends to be relatively low, ranging from about 12% to 20%,depending on the grade of heat available.

Exemplary embodiments offer an alternative approach to recovering wasteheat and using it to produce power. Instead of the ORC equipment,exemplary embodiments could deploy the outflow mode of the VPS cyclewhere O₂/N₂ would be delivered from a semi-centralized air separationplant, and where the on-site, low-grade, waste heat would be used topre-warm the O₂/N₂ stream prior to receiving high-grade heat from theVPS unit's GT or NG-fired engine. That integration would allow a smallerGT (or engine) to service a larger flow of O₂/N₂, reducing the relativeamount of NG burned in the system. The low-grade waste heat that isavailable at the host site would be the first heat source applied to theoutbound O₂/N₂, warming the working fluid (WF) to within 10-degrees ofthe temperature of the waste heat source, and then warming the WF towardthe 1,000° F. that is the optimal pre-expansion temperature for theO₂/N₂.

Thus, the deployment outlined above would allow the available waste heatat an industrial site to be used in a manner that can supply enoughpower to remove (all or a substantial portion of) that facility from thegrid during the daily peak power demand period. Instead of an ORCsolution that inefficiently converts the site's waste heat to a smallportion of the site's daily peak power demand, and does so with costlyequipment, exemplary embodiments allow that site to be fully independentfrom the power grid during peak periods, where that independence ispartially “fueled” by the available waste heat.

Round-trip efficiency (the ratio of the amount of power used to createthe cryogenic fluid (inflow-to-storage mode) to the amount of powerreleased (outflow-from-storage mode)) for exemplary embodiments can becalculated by using the following methodology (with exemplary numbers).All of the disclosed embodiments yield high round-trip efficiency (RTE)rates. An exemplary RTE calculation is as follows.

VPS Round-Trip Efficiency (RTE) Methodology

-   Base Case Assumptions-   Storage: 225,000 gallons of L-Air=1,368,800 pounds of L-Air=3 tanks,    75,000 gallons each Assumptions-   Storage: 225,000 gallons of L-Air=1,368,800 pounds of L-Air=3 tanks,    75,000 gallons each-   Inflow to Storage: 10 hours per day times 5 days per week times    52.14 weeks per year-   Outflow from Storage: 8 hours per day times 5 days per week times    52.14 weeks per year-   Energy Flow-   Inflow-to-Storage: 16.21 MW×10 hours=162.1 MWH/day; 42,288 MWH/year-   Net Outflow-from-Storage: 48.05 MW×8 hours=384.4 MWH/day; 100,211    MWH/year-   Natural Gas (NG) Used During Outflow:177,005 SCF/hr; 161,959,575    BTU/hr-   Heat Rate of VPS Cycle: 3,371 BTU/kWH-   Lower Heating Value (LHV) Energy Content of NG: 915 BTU/SCF    (approximate)

Power Output Content of NG Used

-   MWH of power if NG is used in a highly efficient (60%)    Combined-Cycle Power Plant (i.e., the amount of power output that    could be achieved with the same amount of NG by a high-efficiency    power generation sytem): 59,804 MWH/year

Portion of Energy Output Attributable to Stored Energy

-   Total Power Output−Power Output Attributable to NG=Energy Recovered    from Storage:-   100,211 MWH−59,804 MWH=40,408 MWH-   RTE=Recovered Output÷Inflow-to-Storage 40,408÷42,288=95.55%

In other words, of the 42,288 MWH of inflow-to-storage, 40,408 MWH arerecovered, yielding a 95.55% recovery rate or Round-trip Efficiency(RTE). That relatively high RTE can be achieved with the relativelyhigh-grade heat available for GTs and some engine configurations. Lowergrade heat (say, at about 800° F.) will yield RTE rates closer to about82%. However, in some contexts that RTE is an excellent result,considering the power storage and power production values that aregenerated by the present embodiments. In other contexts, where a highRTE (say, 90% or higher) is essential for economic viability, or whererecoverable waste heat is only available at a lower grade, varioussupplemental heating steps can be introduced, as mentioned throughoutthis document. It should be noted that the above RTE calculation is onlyexemplary and not in any way a limitation on the embodiments disclosedand claimed herein.

Thus, it is seen that systems and methods of semi-centralized powerstorage and distributed power generation and power release and coldrecovery are provided. It should be understood that any of the foregoingconfigurations and specialized components may be interchangeably usedwith any of the apparatus or systems of the preceding embodiments.Although illustrative embodiments are described hereinabove, it will beevident to one skilled in the art that various changes and modificationsmay be made therein without departing from the scope of the disclosure.It is intended in the appended claims to cover all such changes andmodifications that fall within the true spirit and scope of thedisclosure.

1. A system of semi-centralized energy storage and distributed powergeneration, comprising: at least one energy storage facility receivingenergy via an electric grid, the energy being generated at a firstlocation, the energy storage facility being at a second locationdifferent from the first location, the second location being closer toend users of the energy than the first location; the energy storagefacility producing an energy storage medium at the second location andstoring the energy from the first location at the second location in theenergy storage medium, the energy storage medium comprising: liquid air,liquid oxygen, liquid nitrogen, or a combination thereof; at least onemobile stored energy transportation unit configured to carry at least aportion of the energy storage medium to a distributed power generationfacility at a third location different from the first and secondlocations, the third location being closer to end users of the energythan the first location; and a prime mover fluidly connected to thedistributed power generation facility, wherein the energy storage mediumcools an inlet air stream to the prime mover.
 2. The system of claim 1wherein the energy storage facility is an air separation plant.
 3. Thesystem of claim 1 wherein the energy storage facility functions as anenergy service company.
 4. The system of claim 1 wherein the distributedpower generation facility is electrically connected to an electric gridand provides power to the grid.
 5. (canceled)
 6. The system of claim 1wherein the energy storage facility is configured to use a portion ofthe stored energy in a distributed power generation mode.
 7. The systemof claim 1 further comprising a natural gas pipeline fluidly connectedto the distributed power generation facility.
 8. The system of claim 1wherein the power storage facility comprises: a plurality ofcompressors; at least one heat exchanger fluidly connected to at leastone of the compressors; at least one expander fluidly connected to atleast one of the compressors; a mechanical chiller fluidly connected tothe expander; and a storage vessel fluidly connected to the expander. 9.The system of claim 1 wherein the distributed power generation facilitycomprises: a plurality of heat exchangers; at least one expander fluidlyconnected to at least one of the heat exchangers; and a prime moverassembly including a prime mover, the prime mover assembly fluidlyconnected to at least one of the heat exchangers.
 10. A method ofsemi-centrally storing energy and distributing power, comprising:receiving energy from a first location, the energy being received by anenergy storage facility at a second location different from the firstlocation, the second location being closer to end users of the energythan the first location; producing an energy storage medium at thesecond location and storing the energy at the second location in theenergy storage medium, the energy storage medium comprising: liquid air,liquid oxygen, liquid nitrogen, or a combination thereof; transportingat least a portion of the energy storage medium to a third locationdifferent than the first and second locations, the third location beingcloser to end users of the energy than the first location; releasingenergy from the energy storage medium to generate power at the thirdlocation; and providing a portion of outflow power from a prime moverlocated at the third location.
 11. The method of claim 10 whereinstoring energy comprises separating air into liquid oxygen, liquidnitrogen, or a combination thereof.
 12. The method of claim 10 whereingenerating power comprises providing power to an electric grid.
 13. Themethod of claim 10 wherein a portion of the stored energy is used at thesecond location.
 14. The method of claim 10 further comprising providingnatural gas at the third location.
 15. The method of claim 10 whereinstoring power comprises providing a stream of side load refrigerant tocool the power storage medium.
 16. The method of claim 10 whereinreleasing power comprises: pumping to pressure the power storage medium;directing a working fluid in counterflow to the power storage mediumsuch that the working fluid warms the power storage medium and the powerstorage medium condenses the working fluid; directing one or moregaseous products of combustion in counterflow to the power storagemedium such that the gaseous products warm the power storage medium andthe working fluid; and expanding the power storage medium and theworking fluid in generator-loaded expanders.
 17. An integrated electricgrid, fuel source, and surface transport system, comprising: at leastone energy storage facility receiving energy via an electric grid, theenergy being generated at a first location, the energy storage facilitybeing at a second location different from the first location, the secondlocation being closer to end users of the energy than the firstlocation; the energy storage facility producing an energy storage mediumat the second location and storing the energy from the first location atthe second location in the energy storage medium, the energy storagemedium comprising: liquid air, liquid oxygen, liquid nitrogen, or acombination thereof; at least one mobile stored energy transportationunit configured to carry at least a portion of the energy storage mediumto a distributed power generation facility via surface transportsystems, the distributed power generation facility being at a thirdlocation different from the first and second locations, the thirdlocation being closer to end users of the energy than the firstlocation; and a fuel source and a prime mover fluidly connected to thedistributed power generation facility, the prime mover providing aportion of outflow power supplied by the distributed power generationfacility.
 18. The system of claim 17 wherein the energy storage facilityis an air separation plant.
 19. The system of claim 17 wherein theenergy storage facility is configured to use a portion of the storedenergy in a distributed power generation mode.
 20. (canceled)
 21. Thesystem of claim 1 wherein the prime mover is a fueled turbine, andwherein the turbine provides a portion of power supplied by thedistributed power generation facility.
 22. The system of claim 1 whereinthe prime mover is a fueled turbine.
 23. The system of claim 1 whereinthe system is a commercial scale deployment.
 24. The system of claim 1further comprising at least one energy storage facility at a fourthlocation different than the second location, wherein at least one mobilestored energy transportation unit transports energy storage medium fromthe fourth location to the distributed power generation facility. 25.The system of claim 1 wherein the at least one mobile stored energytransportation unit carries at least a portion of the energy storagemedium off-grid to the distributed power generation facility.
 26. Thesystem of claim 1 wherein the prime mover functions as a back-upgenerator.
 27. The system of claim 1 wherein at least one distributedpower generation facility sends power back to the energy storagefacility.
 28. The method of claim 11 further comprising storing at leasta portion of the energy in the energy storage medium as back-up power.29. A method of distributing energy, comprising: receiving energy from afirst location via an electric grid, the energy being received at anenergy storage facility at a second location different from the firstlocation, the second location being closer to end users of the energythan the first location; producing an energy storage medium at thesecond location, storing energy at the second location in the energystorage medium, and transporting energy from the second location to athird location in an energy storage medium via a mode of transportationindependent of an electricity grid, the third location being differentthan the first and second locations and being closer to end users of theenergy than the first location; and using a portion of the energystorage medium to cool an inlet air stream to a prime mover located atthe third location.